10-Q 1 h20087e10vq.txt EL PASO CGP COMPANY - JUNE 30, 2004 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------------- FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2004 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER 1-7176 --------------------- EL PASO CGP COMPANY (Exact Name of Registrant as Specified in its Charter) DELAWARE 74-1734212 (State or Other Jurisdiction (I.R.S. Employer of Incorporation or Organization) Identification No.) EL PASO BUILDING 1001 LOUISIANA STREET 77002 HOUSTON, TEXAS (Zip Code) (Address of Principal Executive Offices)

Telephone Number: (713) 420-2600 Internet Website: www.elpaso.com Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ ] No [X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common stock, par value $3 per share. Shares outstanding on December 3, 2004: 1,000 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- EL PASO CGP COMPANY TABLE OF CONTENTS

CAPTION PAGE ------- ---- PART I -- Financial Information Item 1. Financial Statements........................................ 1 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 24 Cautionary Statement Regarding Forward-Looking Statements... 3637 Item 3. Quantitative and Qualitative Disclosures About Market Risk...................................................... 3738 Item 4. Controls and Procedures..................................... 3839 PART II -- Other Information Item 1. Legal Proceedings........................................... 4142 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.................................................. 4142 Item 3. Defaults Upon Senior Securities............................. 4142 Item 4. Submission of Matters to a Vote of Security Holders......... 4142 Item 5. Other Information........................................... 4142 Item 6. Exhibits.................................................... 4142 Signatures.................................................. 4243

--------------- Below is a list of terms that are common to our industry and used throughout this document: /d = per day Bbl = barrels BBtu = billion British thermal units Bcf = billion cubic feet Bcfe = billion cubic feet of natural gas equivalents MBbls = thousand barrels Mcf = thousand cubic feet Mcfe = thousand cubic feet of natural gas equivalents MMBtu = million British thermal units MMcf = million cubic feet MMcfe = million cubic feet of natural gas equivalents MW = megawatt

When we refer to natural gas and oil in "equivalents," we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Oil includes natural gas liquids unless otherwise specified. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch. When we refer to "us", "we", "our", "ours", or "El Paso CGP", we are describing El Paso CGP Company and/or our subsidiaries. i PART I -- FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS EL PASO CGP COMPANY CONDENSED CONSOLIDATED STATEMENTS OF INCOME (IN MILLIONS) (UNAUDITED)

QUARTER ENDED ~~MARCH~~SIX 31MONTHS ENDED JUNE 30, JUNE 30, ------------------ ------------------- 2003 2003 2004 (RESTATED) 2004 (RESTATED) ----- ---------- ------ ---------- Operating revenues......................................~~....~~ $ ~~564~~505 $ ~~748~~604 $1,042 $1,327 ----- ----- ------ ------ Operating expenses Cost of products and services.........................~~....~~ ~~111~~104 ~~175~~134 212 309 Operation and maintenance.............................~~....~~ ~~130~~120 ~~134~~132 247 261 Depreciation, depletion and amortization..............~~....~~ ~~122~~115 ~~128~~121 228 242 Loss (gain) on long-lived assets......................~~...........~~ ~~181~~-- 8(30) ~~Ceiling~~88 ~~test~~(31) ~~charges...................................... 28 1~~ Taxes, other than income taxes........................~~....~~ 1218 2719 30 46 ----- ----- ~~584~~------ ~~473~~------ 357 376 805 827 ----- ----- ------ ------ Operating income ~~(loss)~~........................................ ~~(20)~~148 ~~275~~228 237 500 Earnings (losses) from unconsolidated affiliates........~~.............~~ 3524 39(54) 59 (15) Other income, net.......................................~~....~~ 67 67 13 13 Interest and debt expense...............................~~....~~ (~~100~~91) (99101) (192) (200) Affiliated interest income (expense), net...............~~.............~~ 5 (147) (79) (14) Distributions on preferred interests of consolidated subsidiaries..........................................~~....~~ -- (7) -- (14) ----- ----- ~~Income~~------ ~~(loss)~~------ Income before income taxes.............................. (93) ~~207~~66 108 270 Income taxes............................................~~....~~ ~~(30)~~32 7119 37 89 ----- ----- ~~Income~~------ ~~(loss)~~------ Income from continuing operations....................... ~~(63)~~61 ~~136~~47 71 181 Discontinued operations, net of income taxes............~~....~~ (5511) (~~222~~931) (139) (1,151) Cumulative effect of accounting changes, net of income taxes.................................................~~....~~ -- -- -- (12) ----- ----- ------ ------ Net income (loss).......................................~~.............~~ $ 50 $(~~118~~884) $ (9868) $ (982) ===== ===== ====== ======

See accompanying notes. 1 EL PASO CGP COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (IN MILLIONS, EXCEPT SHARE AMOUNTS) (UNAUDITED)

~~MARCH~~JUNE 3130, DECEMBER 31, 2004 2003 --------- ------------ ASSETS Current assets Cash and cash equivalents................................. $ ~~176~~86 $ 150 Accounts and notes receivable Customers, net of allowance of $4134 in 2004 and $37 in 2003.................................................. ~~237~~200 ~~311~~291 Affiliates............................................. ~~397~~436 442 Other.................................................. ~~132~~152 8886 Inventory................................................. 49 55 58 Assets ~~from price risk management activities.............. 79 97 Assets~~ held for sale and from discontinued operations..... ~~164~~172 1,~~373~~406 ~~Restricted cash........................................... 108 36~~ Other..................................................... 9772 95220 ------- ------- Total current assets.............................. 1,~~445~~167 2,650 ------- ------- Property, plant and equipment, at cost Pipelines................................................. 6,~~596~~701 6,478 Natural gas and oil properties, at full cost.............. 7,~~389~~244 87,~~304~~230 Power facilities.......................................... ~~372~~373 372 Gathering and processing systems.......................... ~~152~~144 151 Other..................................................... 97 119 ------- ------- 14,~~606~~559 1514,~~424~~350 Less accumulated depreciation, depletion and amortization........................................... 8,~~185~~092 8,~~678~~003 ------- ------- Total property, plant and equipment, net.......... 6,~~421~~467 6,~~746~~347 ------- ------- Other assets Investments in unconsolidated affiliates.................. 1,~~255~~187 1,312 Assets from price risk management activities.............. ~~785~~-- 845 Goodwill and other intangible assets, net................. ~~416~~415 ~~421~~415 Assets of discontinued operations......................... -- 405 Other..................................................... ~~362~~209 435 ------- ------- 21,~~818~~811 3,~~013~~412 ------- ------- Total assets...................................... $10 9,~~684~~445 $12,409 ======= =======

See accompanying notes. 2 EL PASO CGP COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS -- (CONTINUED) (IN MILLIONS, EXCEPT SHARE AMOUNTS) (UNAUDITED)

~~MARCH~~JUNE 3130, DECEMBER 31, 2004 2003 --------~~----~~ ------------ LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities Accounts payable Trade.................................................. $ ~~171~~163 $ ~~197~~196 Affiliates............................................. 7588 110 Other.................................................. ~~183~~162 ~~238~~201 Short-term financing obligations, including current maturities............................................. ~~299~~349 310 Notes payable to affiliates............................... ~~128~~32 906 Liabilities related to discontinued operations............ 3632 ~~658~~696 Other..................................................... ~~568~~374 363 ------- ------- Total current liabilities......................... 1,~~460~~200 2,782 ------- ------- Long-term financing obligations............................. 43,~~713~~640 5,011 ------- ------- Other Deferred income taxes..................................... ~~666~~767 732 Other..................................................... ~~450~~423 432 ------- ------- 1,~~116~~190 1,164 ------- ------- Commitments and contingencies Securities of subsidiaries.................................. ~~175~~156 107 ------- ------- Stockholder's equity Common stock, par value $1 per share; authorized and issued 1,000 shares.................................... -- -- Additional paid-in capital................................ 3,136 3,136 Retained earnings......................................... ~~106~~156 224 Accumulated other comprehensive loss...................... (2233) (15) ------- ------- Total stockholder's equity........................ 3,~~220~~259 3,345 ------- ------- Total liabilities and stockholder's equity........ $10 9,~~684~~445 $12,409 ======= =======

See accompanying notes. 3 EL PASO CGP COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS) (UNAUDITED)

~~QUARTER~~SIX MONTHS ENDED ~~MARCH~~JUNE 3130, ----------------------- 2003 2004 (RESTATED)(1) ------- ------------- Cash flows from operating activities Net loss.................................................. $ (~~118~~68) $ (98982) Less loss from discontinued operations, net of income taxes................................................. (55139) (~~222~~1,151) ------- ------- Net income ~~(loss)~~ before discontinued operations................. ~~(63)~~71 ~~124~~169 Adjustments to reconcile net income ~~(loss)~~ to net cash from operating activities Depreciation, depletion and amortization................ ~~122~~228 ~~128~~242 ~~Ceiling test charges.................................... 28 1~~ Loss (gain) on long-lived assets........................~~.......~~ ~~181~~88 8(31) Earnings from unconsolidated affiliates, adjusted for cash distributions.................................... (1612) ~~(19)~~44 Deferred income ~~tax expense (benefit)~~taxes................................... ~~(74)~~32 5864 Cumulative effect of accounting changes................. -- 12 Other non-cash ~~income~~ items.................................... 211 52(20) Asset and liability changes............................. ~~156~~34 ~~149~~451 ------- ------- Cash provided by continuing operations.................. ~~336~~452 ~~513~~931 Cash provided by ~~(used in)~~ discontinued operations................ ~~170~~159 ~~(223)~~99 ------- ------- Net cash provided by operating activities.......... ~~506~~611 ~~290~~1,030 ------- ------- Cash flows from investing activities Additions to property, plant and equipment................ (~~160~~296) (~~329~~540) Purchases of interests in equity investments.............. (812) (23) Net proceeds from the sale of assets and investments...... ~~336~~81 ~~216~~293 ~~Increase~~Net change in restricted cash............................... ~~(72)~~34 (4347) Net change in notes receivable from unconsolidated affiliates.............................................. 620 (~~115~~259) Other..................................................... 931 ~~(3)~~22 ------- ------- Cash ~~provided by (~~used in) continuing operations...................... ~~111~~(142) (~~276~~534) Cash provided by discontinued operations................ ~~753~~1,113 ~~362~~245 ------- ------- Net cash provided by (used in) investing activities....................................... ~~864~~971 86(289) ------- ------- Cash flows from financing activities Payments to retire long-term debt and other financing obligations............................................. (~~252~~460) (~~290~~297) ~~Decrease~~Net change in ~~notes~~affiliated ~~payable~~advances ~~to unconsolidated affiliates~~payable................. (~~800~~896) (~~316~~682) Proceeds from issuance of securities of subsidiaries...... 7374 -- Net proceeds from the issuance of long-term debt and other financing obligations................................... -- 288 Contributions from discontinued operations................ ~~558~~907 ~~141~~344 Other..................................................... --1 31 ------- ------- Cash used in continuing operations...................... (~~421~~374) (~~174~~346) Cash used in discontinued operations.................... (~~923~~1,272) (~~139~~344) ------- ------- Net cash used in financing activities.............. (1,~~344~~646) (~~313~~690) ------- ------- ~~Increase~~Change in cash and cash equivalents......................... 26(64) 6351 Cash and cash equivalents Beginning of period....................................... 150 128 ------- ------- End of period............................................. $ ~~176~~86 $ ~~191~~179 ======= =======

--------------- (1) Only individual line items in cash flows from operating activities have been restated. Total cash flows from continuing operating, investing and financing activities, as well as discontinued operations, were unaffected. See accompanying notes. 4 EL PASO CGP COMPANY CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (IN MILLIONS) (UNAUDITED)

QUARTER ENDED ~~MARCH~~SIX 31MONTHS ENDED JUNE 30, JUNE 30, ----------------- ----------------- 2003 2003 2004 (RESTATED) 2004 (RESTATED) ---- ---------- ---- ---------- Net income (loss).........................................~~...........~~ $ 50 $(~~118~~884) $(9868) $(982) ---- ----- ---- ----- Foreign currency translation adjustments.................... --(1) 4050 (1) 90 Unrealized net gains (losses) from cash flow hedging activity Unrealized mark-to-market losses arising during period (net of income taxes of $87 and $15 in 2004 and $2416 and $40 in 2003)..................................... (1412) (4428) (26) (72) Reclassification adjustments for changes in initial value to the settlement date (net of income taxes of $42 and $6 in 2004 and $228 and $30 in 2003)............~~......................~~ 72 4113 9 54 ---- ----- ---- ----- Other comprehensive income (loss).................... (711) 3735 (18) 72 ---- ----- ---- ----- Comprehensive income (loss)...............................~~...........~~ $ 39 $(~~125~~849) $(6186) $(910) ==== ===== ==== =====

See accompanying notes. 5 EL PASO CGP COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. BASIS OF PRESENTATION AND LIQUIDITY UPDATE Basis of Presentation We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the U.S. Securities and Exchange Commission. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles. You should read this Quarterly Report on Form 10-Q along with our 2003 Annual Report on Form 10-K, which includes a summary of our significant accounting policies and other disclosures. The financial statements as of June 30, 2004, and for the quarters and six months ended June 30, 2004 and 2003, are unaudited. We derived the balance sheet as of December 31, 2003, from the audited balance sheet filed in our 2003 Annual Report on Form 10-K. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Due to the seasonal nature of our businesses, information for interim periods may not be indicative of the results of operations for the entire year. Our results for all periods presented have been reclassified to reflect our Canadian and certain other international natural gas and oil production operations as discontinued operations. Also, our results for the quarter and six months ended June 30, 2003 have been restated to reflect the accounting impact of a reduction in our historically reported proved natural gas and oil reserves as further discussed in our 2003 Annual Report on Form 10-K. Finally, the prior period information presented in these financial statements includes reclassifications which were made to conform to the current period presentation. These reclassifications had no effect on our previously reported net income or stockholder's equity. Liquidity Update We rely on cash generated from our internal operations and loans from El Paso Corporation (El Paso), our direct parent, through its cash management program as our primary sources of liquidity, as well as proceeds from asset sales and capital contributions from El Paso. We expect that our future funding for working capital needs, capital expenditures and debt service will continue to be provided from some or all of these sources. Under El Paso's cash management program, we have historically and consistently borrowed cash. Currently, one of our subsidiaries, Colorado Interstate Gas Company (CIG), is not advancing funds to El Paso via the cash management program due to its anticipated cash needs. For a further discussion of our participation in El Paso's cash management program, see Note 11. During 2004, El Paso restated its historical financial statements to reflect the accounting impact of revisions to its natural gas and oil reserve estimates and changes in the manner in which it accounted for certain derivative contracts, primarily those related to the hedging of its natural gas production. El Paso received several waivers based on its belief that the restatements would cause a delay in filing its financial statements and would have constituted various events of default under its then existing revolving credit facility and various other financing transactions. El Paso subsequently filed its financial statements within the time frames granted by these waivers. In November 2004, El Paso entered into a new credit agreement with a group of lenders for an aggregate of $3 billion in financings to replace its previous revolving credit facility which was scheduled to mature in June 2005. Upon closing of the new credit agreement, El Paso borrowed $1.25 billion and used approximately $1.2 billion of capacity to support existing letters of credit under its previous revolving credit facility. Our subsidiaries, ANR Pipeline Company (ANR) and CIG, continue to be eligible borrowers under the new credit agreement. Additionally, our interests in ANR, CIG, Wyoming Interstate Gas Company (WIC), and ANR Storage Company are pledged as collateral under the new credit agreement. For a further discussion of El Paso's new credit agreement and other information regarding our financing obligations, see Note 7. Additionally, under several of our financing arrangements, we are required to file financial statements in a timely manner. We have not yet filed our financial statements for the third quarter of 2004; however, no notice 6 has been given as to any violations under these financing arrangements for our failure to file financial statements. We believe that we will file our financial statements prior to any notice being given or within the allowed time frames under these arrangements such that there will be no event of default. 2. SIGNIFICANT ACCOUNTING POLICIES Our significant accounting policies are discussed in our 2003 Annual Report on Form 10-K. The information below provides updating information or required interim disclosures with respect to those policies or disclosure where our policies have changed. Consolidation of Variable Interest Entities In January 2003, the Financial Accounting Standards Board (FASB) issued Financial Interpretation (FIN) No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. This interpretation defines a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity. This standard requires a company to consolidate a variable interest entity if it is allocated a majority of the entity's losses or returns, including fees paid by the entity. In December 2003, the FASB issued FIN No. 46-R, which amended FIN No. 46 to extend its effective date until the first quarter of 2004 for all types of entities, except special purpose entities. In addition, FIN No. 46-R limited the scope of FIN No. 46 to exclude certain joint ventures or other entities that meet the characteristics of businesses. On January 1, 2004, we adopted this standard. Upon adoption, we consolidated Blue Lake Gas Storage Company. The overall impact of this action is described in the following table:

Blue Lake Gas Storage owns and operates a 47 Bcf gas storage facility in Michigan. One of our subsidiaries operates the natural gas storage facility and we inject and withdraw all natural gas stored in the facility. We own a 75 percent equity interest in Blue Lake. This entity has $11 million of third party debt as of June 30, 2004 that is non-recourse to us. We consolidated Blue Lake because we are allocated a majority of Blue Lake's losses and returns through our equity interest in Blue Lake. We have significant interests in a number of other variable interest entities. We were not required to consolidate these entities under FIN No. 46 and, as a result, our method for accounting for these entities did not change. As of January 1, 2004, these entities consisted primarily of 10 equity investments held in our Power segment that had interests in power generation and transmission facilities with a total generating capacity of approximately 3,000 gross MW. We operate many of these facilities but do not supply a significant portion of the fuel consumed or purchase a significant portion of the power generated by these facilities. The long-term debt issued by these entities is recourse only to the power project. As a result, our exposure to these entities is limited to our equity investments in and advances to the entities (approximately $801 million as of June 30, 2004) and our guarantees and other agreements associated with these entities (a maximum of $44 million as of June 30, 2004). 7 Accounting for Asset Retirement Obligations On January 1, 2003, we adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations. This standard required that we record a liability for retirement and removal costs of long-lived assets used in our businesses. In 2003, we recorded a charge as a cumulative effect of accounting change of approximately $12 million, net of income taxes related to its adoption. New Accounting Pronouncements Not Yet Adopted Accounting for Natural Gas and Oil Producing Activities. In September 2004, the SEC issued Staff Accounting Bulletin No. 106. This pronouncement will require companies that use the full cost method for accounting for their oil and gas producing activities to include an estimate of future asset retirement costs to be incurred as a result of future development activities on proved reserves in their calculation of depreciation, depletion and amortization. It will also require these companies to exclude future cash outflows associated with settling asset retirement liabilities from their full cost ceiling test calculation. Finally, this standard will require disclosure of the impact of a company's asset retirement obligations on its oil and gas producing activities, ceiling test calculations and depreciation, depletion and amortization calculations. We will adopt the provisions of this pronouncement in the first quarter of 2005 and are currently evaluating its impact, if any, on our consolidated financial statements. Accounting for Inventory Costs. In November 2004, the FASB issued SFAS No. 151, Inventory Costs, an amendment of ARB No. 43, Chapter 4. This statement will require expensing certain costs that have historically been capitalized as inventory. The statement will also require the capitalization of certain fixed overhead costs associated with operating facilities involved in inventory management. The provisions of SFAS No. 151 are effective for fiscal years beginning after June 15, 2005, and will impact certain inventory costs we incur after January 1, 2006. We are currently evaluating the impact, if any, of this standard on our financial statements. 8 3. DIVESTITURES Sales of Assets and Investments During 2004, we completed and announced the sale of a number of assets and investments. The following table summarizes the proceeds from these sales:

COMPLETED COMPLETED THROUGH AFTER ~~MARCH~~JUNE 3130, 2004 SIGNIFICANT ASSETS AND INVESTMENTS SOLD ~~MARCH~~JUNE 3130, 2004 OR ANNOUNCED TO DATE(1) TOTAL --------------------------------------- -------------- ----------------------- ----- (IN MILLIONS) Unregulated Production............................................. $ ~~352~~-- $24 58 $ ~~410~~24 - ~~Natural~~Brazilian ~~gas and oil properties in Canada(2) - International~~ exploration and production assets(32) Power.................................................. 392 89-- 92 - Utility Contract Funding (UCF)(3) - Mohawk River Funding IV(43) - ~~Equity interest in the~~ Bastrop Company ~~power~~equity investment(3) Field Services - ~~Fulton~~Dauphin ~~power~~Island ~~facility(~~and Mobile Bay equity -- 3 3 investments(4)..................................... ------ ---- ------ Total continuing......................................... ~~355~~92(54) ~~147~~27 ~~502~~119 Discontinued............................................. ~~891~~1,261 1030 ~~901~~1,291 - Natural gas and oil production properties in Canada(3) - Aruba and Eagle Point refineries and other petroleum assets(43) - ~~Other~~Remaining ~~petroleum~~Canadian and other international production assets(32) ------ ---- ------ Total.................................................... $1,~~246~~353 $~~157~~57 $1,~~403~~410 ====== ==== ======

--------------- (1) Sales that have not been completed are estimates, subject to customary regulatory approvals, final negotiations and other conditions. (2) These sales were or will be completed after June 30, 2004. (3) These sales were completed as of June 30, 2004. (4) We also received property, plant and equipment of approximately $9 million and issued other obligations totaling approximately $7 million associated with these sales. (5) Proceeds exclude returns of invested capital and cash transferred with the assets sold and include costs incurred in preparing assets for disposal. These items decreased our sales proceeds by $11 million for the six months ended June 30, 2004. 9

SIGNIFICANT ASSETS AND INVESTMENTS SOLD PROCEEDS --------------------------------------- -------- (IN MILLIONS) As of ~~March~~June 3130, 2003 Regulated Pipelines................................................. $ 4363 - Panhandle gathering system located in Texas - 2.1 percent equity interest in Alliance pipeline and related assets - Helium processing operations in Oklahoma - Table Rock sulfur extraction facility Unregulated Production................................................ ~~168~~144 - Natural gas and oil properties in ~~western Canada,~~ New Mexico and the Gulf of Mexico Field Services............................................ 3594 - Gathering systems located in Wyoming - Midstream assets in the Mid-Continent region ---- Total continuing............................................ ~~246~~301(1) Discontinued................................................ ~~514~~581 - Corpus Christi refinery - Florida petroleum terminals and tug and barge operations - Louisiana lease crude business - Coal reserves and properties in West Virginia, Virginia and Kentucky - Natural gas and oil production properties in Canada ----- Total....................................................... $882 ~~760~~ ======

--------------- (1) Proceeds exclude returns of invested capital and cash transferred with the assets sold and include costs in preparing assets for disposal. These items decreased our sales proceeds by $8 million for the six months ended June 30, 2003. See Notes 4 and 11 for a discussion of gains, losses and asset impairments related to the sales above. Under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we classify assets being disposed of as held for sale or, if appropriate, discontinued operations if they have received appropriate approvals by El Paso's management or Board of Directors and have met other criteria. As of June 30, 2004 and December 31, 2003, we had $7 million of current assets held for sale in our balance sheets. Our assets held for sale related to domestic power assets in our Power segment that were approved by El Paso's Board of Directors for sale in 2003. Discontinued Operations International Natural Gas and Oil Operations. During 2004, our Canadian and certain other international natural gas and oil production operations were approved for sale. As of November 2004, we have completed the sale of all of our Canadian operations and substantially all of our operations in Indonesia for total proceeds of approximately $389 million. During the six months ended June 30, 2004, we recognized approximately $93 million in asset impairments based on our decision to sell these assets and losses on completed asset sales. We expect to complete the sale of the remainder of these properties in 2004 and early 2005. Petroleum Markets. During the first quarter of 2003, El Paso's Board of Directors approved the sales of our Eagle Point refinery, our asphalt business, our Florida terminal, tug and barge business and our lease crude operations. In June 2003, El Paso's Board of Directors authorized the sale of our remaining petroleum markets operations, including our Aruba refinery, our Unilube blending operations, our domestic and international terminalling facilities and our petrochemical and chemical plants. Based on our intent to dispose of these operations, we were required to adjust these assets to their estimated fair value. As a result, we recognized a pre-tax impairment charge of approximately $987 million during the second quarter of 2003 related to our petroleum and chemical assets. Our second quarter 2003 charge was in addition to the $350 million pre-tax 10 impairment charge recognized during the first quarter of 2003 when we announced our intent to sell our Eagle Point refinery and several of our chemical assets. These impairments were based on a comparison of the carrying value of these assets to their estimated fair value, less selling costs. We also recorded realized gains of approximately $52 million in the first six months of 2003 from the sale of our Corpus Christi refinery and Florida terminalling and marine assets. In the first and second quarters of 2004, we completed the sales of our Aruba and Eagle Point refineries for $880 million and used a portion of the proceeds to repay $370 million of debt associated with the Aruba refinery. In addition, in the first quarter of 2004, we reclassified our petroleum ship charter operations from discontinued operations to continuing operations in our financial statements based on our decision to retain these operations. Our financial statements for all periods presented reflect this change. Coal Mining. In 2002, El Paso's Board of Directors authorized the sale of our coal mining operations. These operations consisted of fifteen active underground and two surface mines located in Kentucky, Virginia and West Virginia. The sale of these operations was completed in 2003 for $92 million in cash and $24 million in notes receivable, which were settled in the second quarter of 2004. We did not record a significant gain or loss on these sales. Our petroleum markets, coal mining and other international natural gas and oil production operations discussed above are classified as discontinued operations in our financial statements for all of the historical periods presented. All of the assets and liabilities of these discontinued businesses are classified as current assets and liabilities as of June 30, 2004. The summarized financial results and financial position data of our discontinued operations were as follows:

INTERNATIONAL NATURAL GAS AND OIL PETROLEUM PRODUCTION COAL MARKETS OPERATIONS MINING TOTAL --------- ------------- ------ ------- (IN MILLIONS) Operating Results Data QUARTER ENDED ~~MARCH~~JUNE 3130, 2004 Revenues.........................................~~........~~ $ ~~639~~54 $ 1 $ -- $ ~~639~~55 Costs and expenses...............................~~........~~ (~~653~~77) (3) -- (~~653~~80) ~~Loss~~Gain on long-lived assets........................~~........~~ ~~(42)~~4 -- ~~(42)~~-- 4 Other ~~expense~~income.....................................~~.......~~ ~~(2)~~1 -- ~~(2) Interest and debt expense................................ (3)~~ -- ~~(3)~~1 ------- ----- ---- ------- Loss before income taxes.........................~~........~~ (6118) (2) -- (6120) Income taxes.....................................~~........~~ (3) (6) -- (69) ------- ----- ---- ------- ~~Loss~~Income (loss) from discontinued operations, net of income taxes................................ $ (5515) $ 4 $ -- $ (5511) ======= ===== ==== ======= QUARTER ENDED ~~MARCH~~JUNE 3130, 2003 Revenues.........................................~~........~~ $ 21,~~168~~511 $ 2720 $ 2-- $ 1,~~195~~531 Costs and expenses...............................~~........~~ (21,~~132~~612) (2133) -- (21,~~153~~645) Loss on long-lived assets........................~~........~~ (~~296~~990) (35) -- (~~299~~995) Other ~~income~~expense.................................... (21) -- -- (21) Interest and debt expense........................ 7(4) 1-- 8-- (4) ------- ----- ---- ------- ~~Income~~Loss ~~(loss)~~ before income taxes......................... (~~253~~1,116) 4(18) -- (~~249~~1,134) Income taxes.....................................~~........~~ (28198) 1(5) -- (27203) ------- ----- ---- ------- ~~Income~~Loss ~~(loss)~~ from discontinued operations, net of income taxes..........................................~~........~~ $ (~~225~~918) $ 3(13) $ -- $ (~~222~~931) ======= ===== ==== =======

INTERNATIONAL NATURAL GAS AND OIL PETROLEUM PRODUCTION COAL MARKETS OPERATIONS MINING TOTAL --------- --------------- ~~MARCH 31, DECEMBER 31, 2004 2003~~ ------~~---~~ -------~~-----~~ (IN MILLIONS) ~~Financial~~SIX ~~Position~~MONTHS ~~Data~~ENDED ~~Assets~~JUNE of30, ~~discontinued~~2004 ~~operations Accounts and notes receivables~~Revenues......................................... $ 69693 $ ~~259~~28 ~~Inventory~~$ -- $ 721 Costs and expenses............................... (730) (47) -- (777) Loss on long-lived assets........................ 5(38) ~~385~~(93) ~~Other~~-- ~~current~~(131) ~~assets~~Other expense...................................... 31(1) ~~131~~-- ~~Property,~~-- ~~plant~~(1) Interest and ~~equipment,~~debt ~~net~~expense........................ 26(3) ~~521~~1 ~~Other~~-- ~~non~~(2) -~~current~~------ ~~assets~~----- ---- ------- Loss before income taxes......................... (79) (111) -- (190) Income taxes..................................... 26(9) 70(42) -- (51) ------- ----- ---- ~~Total~~------- ~~assets~~Loss offrom discontinued operations, net of income taxes.......................................... $~~157~~ (70) $~~1,366~~ (69) $ -- $ (139) ======= ===== ==== ~~Liabilities~~======= ofSIX ~~discontinued~~MONTHS ~~operations~~ENDED ~~Accounts~~JUNE ~~payable~~30, 2003 Revenues.......................................... $ 123,679 $ ~~172~~46 ~~Other~~$ ~~current~~27 ~~liabilities~~$ 3,752 Costs and expenses............................... (3,744) (47) (21) (3,812) Loss on long-lived assets........................ 18(1,286) 86(14) ~~Long-term~~(3) ~~debt~~(1,303) Other income (expense)........................... (14) -- 1 (13) Interest and debt expense........................ (4) 1 -- ~~374~~(3) ~~Other~~------- ~~non~~-~~current~~---- ~~liabilities~~---- ------- Income (loss) before income taxes................ (1,369) (14) 4 (1,379) Income taxes..................................... 6(226) 26(3) 1 (228) ------- ----- ---- ~~Total~~------- ~~liabilities~~Income of(loss) from discontinued operations, net of income taxes................................ $(1,143) 36$ (11) $ ~~658~~3 $(1,151) ======= ===== ==== =======

~~2004~~INTERNATIONAL ~~2003~~NATURAL GAS AND OIL PETROLEUM PRODUCTION MARKETS OPERATIONS TOTAL --------- ------------- ------ (IN MILLIONS) ~~Net~~Financial ~~realized~~Position ~~loss~~Data ~~(gain)~~JUNE 30, 2004 Assets of discontinued operations Accounts and notes receivable.................... $ 60 $ 11 $ 71 Inventory........................................ $7 84-- ~~$(1)~~7 ~~Asset~~Other ~~impairments~~current assets............................. 7 2 9 Property, plant and equipment, net............... 9722 933 55 Other non-current assets......................... 23 -- 23 ------ ---- ~~Loss~~------ onTotal ~~long~~assets................................... $ 119 $ 46 $ 165 ====== ==== ====== Liabilities of discontinued operations Accounts payable................................. $ 12 $ -~~lived~~- ~~assets~~$ 12 Other current liabilities........................ 14 -- 14 Other non-current liabilities.................... 6 -- 6 ------ ---- ------ Total liabilities.............................. $~~181~~ 32 $ 8-- $ 32 ====== ==== ======

~~MARCH~~INTERNATIONAL ~~31,~~NATURAL ~~DECEMBER~~GAS ~~31,~~AND ~~2004~~OIL ~~2003~~PETROLEUM PRODUCTION MARKETS OPERATIONS TOTAL --------- ------------- ------ (IN MILLIONS) ~~Net~~DECEMBER ~~assets~~31, ~~(liabilities)~~2003 ~~Derivatives~~Assets ~~designated~~of asdiscontinued ~~hedges~~operations Accounts and notes receivable.................... $ 259 $ 22 $ 281 Inventory........................................ ~~$(144)~~385 ~~$(124)~~3 ~~Derivatives~~388 ~~from~~Other ~~power~~current ~~contract restructuring activities~~assets............................. 131 8 139 Property, plant and equipment, net............... 521 399 920 Other non-current assets......................... ~~864(1)~~70 ~~942~~6 76 ------ ---- ------ ~~Net~~Total assets................................... ~~from~~$1,366 ~~price~~$438 ~~risk~~$1,804 ~~management~~====== ~~activities(2)~~==== ====== Liabilities of discontinued operations Accounts payable................................. $ ~~720~~172 $ ~~818~~38 $ 210 Other current liabilities........................ 86 -- 86 Long-term debt................................... 374 -- 374 Other non-current liabilities.................... 26 3 29 ------ ---- ------ Total liabilities.............................. $ 658 $ 41 $ 699 ====== ==== ======

4. LOSS (GAIN) ON LONG-LIVED ASSETS Our loss (gain) on long-lived assets consists of realized gains and losses on sales of long-lived assets and impairments of long-lived assets, goodwill and other intangible assets that are a part of our continuing operations. During each of the periods ended June 30, our loss (gain) on long-lived assets was as follows:

~~MARCH~~SIX ~~31,~~MONTHS ~~DECEMBER~~QUARTER 31ENDED ENDED JUNE 30, ~~2004~~JUNE ~~2003~~30, -------------- ------------ ~~(IN~~2004 ~~MILLIONS)~~2003 ~~Current~~2004 ~~maturities~~2003 of----- ~~long~~-~~term~~---- ~~debt~~---- ~~and~~---- ~~other~~(IN ~~financing~~MILLIONS) ~~obligations~~Net realized gain......................................~~.........~~ $ ~~298~~(2) $(30) ~~310~~$ ~~Short-term~~(3) ~~financing~~$(31) ~~obligations~~Asset impairments...................................... 12 -- 91 -- ---- ---- ---- ~~Total short~~-~~term~~--- ~~financing~~Loss ~~obligations~~(gain) on long-lived assets..................... $ ~~299~~-- $(30) ~~310~~$ 88 $(31) ====== ====== ~~Long-term financing obligations............................. $4,713 $5,011~~ ====== ======

Our 2004 loss on long-lived assets occurred primarily in our Power segment, which recognized an $89 million impairment in the first quarter of 2004 related to the sale of our subsidiary, UCF, which owned a restructured power contract. Our 2003 gain on long-lived assets was primarily related to a $19 million gain recorded in the second quarter of 2003 on the sale of our Mid-Continent midstream assets in our Field Services segment, a $6 million gain on the Table Rock sulfur extraction facility in our Pipelines segment and a $5 million gain on the sale of non-full cost pool assets in our Production segment. 13 5. PRICE RISK MANAGEMENT ACTIVITIES The following table summarizes the carrying value of the derivatives used in our price risk management activities as of June 30, 2004 and December 31, 2003. In the table, derivatives designated as hedges primarily consist of instruments used to hedge our natural gas and oil production. Derivatives from power contract restructuring activities relate to power purchase and sale agreements that arose from our activities in that business.

~~NET~~JUNE ~~PROCEEDS/~~30, ~~REPAYMENTS~~DECEMBER ~~COMPANY~~31, ~~TYPE~~2004 ~~INTEREST~~2003 ~~RATE PRINCIPAL IN DEBT DUE DATE~~ ------- -~~---~~ ------------- ~~--------- ------------- --------~~ (IN MILLIONS) ~~Repayments~~Net Elassets ~~Paso~~(liabilities) ~~CGP~~Derivatives ~~Note~~designated ~~LIBOR~~as ~~+ 3~~hedges.5%......................... $(161) ~~200~~ $(124) ~~200~~Derivatives Elfrom ~~Paso~~power ~~CGP~~contract ~~Recourse~~restructuring ~~note 8~~activities(1).5%......................................... ~~45 45 El Paso CGP Long~~-~~term~~- ~~debt~~942 ~~Various 7 7~~ ----- ----- ~~Repayments~~Net ~~through~~assets ~~March~~(liabilities) ~~31,~~from ~~2004~~price risk management activities(2)........... ~~252 252 El Paso CGP Note 6~~.~~2% 190 190 El Paso CGP Notes 10~~.~~25%~~........................... ~~38 38 El Paso CGP Other long-term debt Various 23 23 ----- -----~~ $(161) ~~503~~ $ ~~503~~818 ===== =====

--------------- (1) We sold our subsidiaries that own these derivative contracts in 2004. See Note 4 for a discussion of the net losses related to these sales. (2) Included in non-current assets from price risk management activities, other non-current liabilities and other current assets and liabilities in our balance sheet. 6. INVENTORY We had $49 million and $55 million of inventory as of June 30, 2004 and December 31, 2003, of which the majority was materials and supplies. 7. DEBT, OTHER FINANCING OBLIGATIONS AND OTHER CREDIT FACILITIES We had the following long-term and short-term borrowings and other financing obligations:

~~MARCH~~JUNE 30, DECEMBER 31, 2004 2003 --------~~-------~~ ~~SITES EXPECTED HIGH~~ ----- -------- ~~----~~ (IN MILLIONS) ~~Operating~~Current maturities of long-term debt and other financing obligations...............................................~~....~~ $ 95348 $~~152~~ ~~Non~~310 Short-~~operating...............................................~~term 30financing ~~60 Superfund~~obligations............................~~.......................~~ 51 8-- ------ ------ Total short-term financing obligations.................... $ 349 $ 310 ====== ====== Long-term financing obligations.............................~~....~~ $~~130~~3,640 $~~220~~5,011 ====== ======

14 Long-Term Financing Obligations From January 1, 2004 through the date of this filing, we had the following changes in our long-term financing obligations:

~~OTHER~~NET ~~PENSION~~INCREASE/ ~~POSTRETIREMENT~~REDUCTION ~~BENEFITS~~COMPANY ~~BENEFITS~~TYPE INTEREST RATE PRINCIPAL IN DEBT DUE DATE ------- ---- ------------- -- ~~2004 2003 2004 2003~~ ------- ---- --------- -------- (IN MILLIONS) ~~Service~~Issuances ~~cost................................................~~and $other increases Blue Lake Gas Storage(1) Non--recourse $term loan LIBOR + 1.2% $ 14 $ 14 2006 ------ $------ ~~Interest~~Increases ~~cost~~through June 30, 2004................... $ 14 $ 14 ====== ====== Repayments and other retirements El Paso CGP Note LIBOR + 3.~~...........................~~5% 1$ 1200 1$ 200 El Paso CGP Note 6.2% ~~Expected~~190 ~~return~~190 onEl ~~plan~~Paso ~~assets~~CGP Recourse note 8.~~.............................~~5% ~~(1)~~45 45 Mohawk River Funding IV(2) ~~(1)~~Non-recourse note 7.75% 72 72 Utility Contract Funding(12) ~~Settlements,~~Non-recourse ~~curtailment,~~senior ~~and~~notes ~~special~~7.944% ~~termination~~815 ~~benefits..................................................~~815 --Other Long--term --debt ~~(6)~~Various 25 25 --- --- --- --- ~~Net~~Decreases ~~benefit~~through ~~income~~June 30, 2004................... 1,347 1,347 El Paso CGP Notes 10.~~....................~~25% $38 38 Other Long--term $debt Various 5 5 ------ $------ $~~(5)~~1,390 $1,390 === === === ===

--------------- (1) This debt was consolidated as a result of adopting FIN No. 46 (see Note 2). (2) This debt was eliminated when we sold our interests in Mohawk River Funding IV and UCF. Credit Facilities In November 2004, El Paso entered into a new credit agreement with a group of lenders for an aggregate of $3 billion in financings. This new credit agreement replaced El Paso's previous revolving credit facility. The new credit agreement is comprised of a $1.25 billion five-year term loan, a $1 billion three-year revolving credit facility under which El Paso and participating subsidiaries can issue letters of credit, and a $750 million five-year funded letter of credit facility. The $750 million letter of credit facility will provide the ability to issue letters of credit or borrow any unused capacity as a term loan. Upon closing of the new credit agreement, El Paso borrowed $1.25 billion under the term loan and used its $750 million letter of credit facility and approximately $0.4 billion of the $1 billion revolving credit facility to support then existing letters of credit of approximately $1.2 billion. Our subsidiaries, ANR and CIG, continue to be eligible borrowers under the new credit agreement. Additionally, our interests in ANR, CIG, WIC, and ANR Storage Company are pledged as collateral under the new credit agreement. Restrictive Covenants Our restrictive covenants are discussed in our 2003 Annual Report on Form 10-K. For an update of matters that have or could impact these covenants, including the restatements of El Paso's and our historical financial statements and associated waivers obtained, see Note 1, Liquidity Update of this Quarterly Report on Form 10-Q. 15 8. COMMITMENTS AND CONTINGENCIES Legal Proceedings Grynberg. A number of our subsidiaries were named defendants in actions filed in 1997 brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. The plaintiff in this case seeks royalties that he contends the government should have received had the volume and heating value been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). Discovery is proceeding. Our costs and legal exposure related to these lawsuits and claims are not currently determinable. Will Price (formerly Quinque). A number of our subsidiaries are named as defendants in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands and seek to recover royalties that they contend they should have received had the volume and heating value of natural gas produced from their properties been differently measured, analyzed, calculated and reported, together with prejudgment and postjudgment interest, punitive damages, treble damages, attorneys' fees, costs and expenses, and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. Plaintiffs' motion for class certification of a nationwide class of natural gas working interest owners and natural gas royalty owners was denied on April 10, 2003. Plaintiffs' were granted leave to file a Fourth Amended Petition, which narrows the proposed class to royalty owners in wells in Kansas, Wyoming and Colorado and removes claims as to heating content. A second class action has since been filed as to the heating content claims. Our costs and legal exposure related to these lawsuits and claims are not currently determinable. MTBE. In compliance with the 1990 amendments to the Clean Air Act, we used the gasoline additive, methyl tertiary-butyl ether (MTBE) in some of our gasoline. We have also produced, bought, sold and distributed MTBE. A number of lawsuits have been filed throughout the U.S. regarding MTBE's potential impact on water supplies. We and our subsidiaries are currently one of several defendants in over 50 such lawsuits nationwide, which, with the exception of two lawsuits recently filed in a California state court, have been consolidated for pre-trial purposes in multi-district litigation in the U.S. District Court for the Southern District of New York. The plaintiffs generally seek remediation of their groundwater, prevention of future contamination, a variety of compensatory damages, punitive damages, attorney's fees, and court costs. Our costs and legal exposure related to these lawsuits and claims are not currently determinable. Reserves. We have been named as a defendant in a purported class action claim styled, GlickenHaus & Co. et. al. v. El Paso Corporation, El Paso CGP Company, et. al., filed in April 2004 in federal court in Houston. The plaintiffs have additionally sued several individuals. The plaintiffs generally allege that our reporting of oil and gas reserves was materially false and misleading between February 2000 and February 2004. This lawsuit has been consolidated with other purported securities class action lawsuits in Oscar S. Wyatt et. al. v. El Paso Corporation et. al. pending in federal court in Houston. Our costs and legal exposure related to this lawsuit and claims are not currently determinable. Governmental Investigations Power Restructuring. In October 2003, El Paso announced that the SEC had authorized the staff of the Fort Worth Regional Office to conduct an investigation of certain aspects of our periodic reports filed with the SEC. The investigation appears to be focused principally on our power plant contract restructurings and the related disclosures and accounting treatment for the restructured power contracts, including in particular the Eagle Point restructuring transaction completed in 2002. We are cooperating with the SEC investigation. 16 Reserve Revisions. In March 2004, El Paso received a subpoena from the SEC requesting documents relating to its December 31, 2003 natural gas and oil reserve revisions. El Paso and El Paso's Audit Committee have also received federal grand jury subpoenas for documents with regard to those reserve revisions. We are assisting El Paso and the Audit Committee in their efforts to cooperate with the SEC's and the U.S. Attorney's investigations of this matter. CFTC Investigation. In April 2004, our affiliates elected to voluntarily cooperate with the Commodity Futures Trading Commission (CFTC) in connection with the CFTC's industry-wide investigation of activities affecting the price of natural gas in the fall of 2003. Specifically, our affiliates provided information relating to storage reports provided to the Energy Information Administration for the period of October 2003 through December 2003. In August 2004, the CFTC announced they had completed the investigation and found no evidence of wrongdoing. Iraq Oil Sales. In September 2004, we received a subpoena from the grand jury of the U.S. District Court for the Southern District of New York to produce records regarding the United Nations' Oil for Food Program governing sales of Iraqi oil. The subpoena seeks various records relating to transactions in oil of Iraqi originating during the period from 1995 to 2003. In November 2004, we received an order from the SEC to provide a written statement and to produce certain documents in connection with the Oil for Food Program. We have also received an inquiry from the United States Senate's Permanent Subcommittee of Investigations related to a specific transaction in 2000. In September 2004, the Special Advisor to the Director of Central Intelligence issued a report on the Iraqi regime, including the Oil for Food Program. In part, the report found that the Iraqi regime earned kick backs or surcharges associated with the Oil for Food program. The report did not name U.S. companies or individuals for privacy reasons, but according to various news reports congressional sources have identified The Coastal Corporation and the former chairman and CEO of Coastal, among others, as having purchased Iraqi crude during the period when allegedly improper surcharges were assessed by Iraq. We are cooperating with the U.S. Attorney's and Senate Subcommittee's investigations of this matter. In addition to the above matters, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. There are also other regulatory rules and orders in various stages of adoption, review and/or implementation, none of which we believe will have a material impact on us. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current reserves are adequate. As of June 30, 2004, we had approximately $29 million accrued for all outstanding legal matters. Environmental Matters We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of June 30, 2004, we had accrued approximately $130 million, including approximately $129 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $1 million for related environmental legal costs, which we anticipate incurring through 2027. Of the $130 million accrual, $87 million was reserved for facilities we currently operate, and $43 million was reserved for non-operating sites (facilities that are shut down or have been sold) and Superfund sites. 17 Our reserve estimates range from approximately $130 million to approximately $212 million. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued ($35 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($95 million to $177 million) and if no one amount in that range is more likely than any other, the lower end of the range has been accrued. By type of site, our reserves are based on the following estimates of reasonably possible outcomes.

JUNE 30, 2004 ~~2003~~--------------- SITES EXPECTED HIGH ----- -------- ---- (IN MILLIONS) ~~Total EBIT~~Operating................................................... $ 2187 $~~320~~139 ~~Interest and debt expense~~Non-operating................................... ~~(100) (99) Affiliated interest expense, net~~............ 39 66 Superfund................ ~~(14) (7) Distributions on preferred interests of consolidated subsidiaries~~...................................~~...........~~ --4 (7) ~~Income~~---- ~~taxes~~---- Total................................................ ~~30 (71) ----- ---- Income (loss) from continuing operations~~.....~~..........~~ $130 ~~(63)~~ $~~136~~212 ===== ====

Below is a reconciliation of our accrued liability from January 1, 2004 to June 30, 2004 (in millions): Balance as of January 1, 2004............................... $131 Additional/adjustments for remediation activities........... 2 Payments for remediation activities......................... (8) Other charges, net.......................................... 5 ---- Balance as of June 30, 2004................................. $130 ====

For the remainder of 2004, we estimate that our total remediation expenditures will be approximately $22 million. In addition, we expect to make capital expenditures for environmental matters of approximately $29 million in the aggregate for the years 2004 through 2008. These expenditures primarily relate to compliance with clean air regulations. CERCLA Matters. We have received notice that we could be designated, or have been asked for information to determine whether we could be designated, as a Potentially Responsible Party (PRP) with respect to 27 active sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state equivalents. We have sought to resolve our liability as a PRP at these sites through indemnification by third-parties and settlements which provide for payment of our allocable share of remediation costs. As of June 30, 2004, we have estimated our share of the remediation costs at these sites to be between $4 million and $7 million. Since the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these issues are included in the previously indicated estimates for Superfund sites. It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws and regulations and claims for damages to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties relating to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current reserves are adequate. Rates and Regulatory Matters In November 2004, the FERC issued an industry-wide Proposed Accounting Release that, if enacted as written, will disallow the capitalization of certain costs that are part of our pipeline integrity program. The 18 accounting release is proposed to be effective January 2005 following a period of public comment on the release. We are currently reviewing the release and have not determined what impact, if any, this release will have on our consolidated financial statements. While the outcome of these matters cannot be predicted with certainty, we believe we have established appropriate reserves for these matters. However, it is possible that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly. The impact of these changes may have a material effect on our results of operations, our financial position and our cash flows in the periods these events occur. Guarantees We are involved in various joint ventures and other ownership arrangements that sometimes require additional financial support that results in the issuance of financial and performance guarantees. See our 2003 Annual Report on Form 10-K for a description of each type of guarantee. As of June 30, 2004, we had approximately $14 million of both financial and performance guarantees not otherwise reflected in our financial statements. 9. RETIREMENT BENEFITS The components of net benefit cost (income) for our pension and postretirement benefit plans for the periods ended June 30 are as follows:

QUARTER ENDED ~~MARCH~~JUNE 3130, SIX MONTHS ENDED JUNE 30, ------------------------------ ------------------------------~~----~~ ~~REGULATED~~OTHER ~~UNREGULATED~~OTHER PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS --------- --- -------------- ------------ ~~FIELD PIPELINES PRODUCTION POWER SERVICES CORPORATE(1) TOTAL~~ --------- ----- 2004 2003 2004 2003 2004 2003 2004 2003 ----- ----- ----- ----- ---- ---- ----- ----- (IN MILLIONS) ~~2004~~Service ~~Revenues from external customers~~cost................ $~~237~~-- $~~178(2)~~-- $-- 54 $-- 79 $ ~~16 $564 Intersegment revenues.......................~~ -- 12$ --1 $-- ~~(12)~~ $-- ~~Operation~~Interest ~~and maintenance expense~~cost........... ~~59 42 23 6 -- 130 Depreciation, depletion and amortization~~.... 301 851 41 1 2 ~~122~~2 ~~Loss~~2 on3 ~~long-lived~~Expected ~~assets...................~~return --on 93plan ~~88 -- -- 181 Ceiling test charges~~assets....................~~....~~ --(1) 28(1) -- -- ~~-- 28 Operating income~~ (~~loss~~2)~~.....................~~ ~~$110 $~~(~~64) $(80) $ 11 $~~ 3 ~~(20~~) ~~Earnings~~ (~~losses~~1) ~~from unconsolidated affiliates................................ 22~~ (21) 12Settlements, 3curtailment, --and 35special ~~Other~~termination ~~income~~benefits..................~~..............~~ -- -- 5 -- ~~1 6~~ -- -- ---- ---- (6) ---- ---- ---- EBIT........................................ $132 $(66) $(63) $ 14 $ 4 $ 21 ==== ==== ==== ==== ==== ==== 2003 Revenues from external customers............ $293 $249(2) $ 59 $115 $ 7 $723 Intersegment revenues....................... (1) 24 -- ~~13 (11) 25(3) Operation and maintenance expense........... 58 40 27 9~~ -- ~~134 Depreciation, depletion and amortization.... 28 91 4 2 3 128 (Gain) loss on long~~-~~lived assets............~~ -- 9 -- ~~(1)~~ -- ~~8 Ceiling test charges........................~~ -- 1 -- -- -- 1Net ~~Operating~~benefit ~~income~~cost (~~loss~~income)...............~~......~~ $~~153~~-- $~~106~~-- $ 121 $ ~~12 $ (8) $275 Earnings (losses) from unconsolidated affiliates................................ 23 3 15 (~~1) ~~(1) 39 Other income (expense)...................... (3)~~ $-- 5 $-- ~~4 6 ---- ---- ---- ---- ---- ---- EBIT........................................~~ $~~173~~ ~~$109~~1 $ ~~32 $ 11 $~~ (54) ~~$320~~ ==== ==== ==== ==== === === === ===

We made $2 million and $4 million of cash contributions to our other postretirement plans during the six months ended June 30, 2004 and 2003. We expect to contribute an additional $7 million to our other postretirement plans in 2004. We do not anticipate making any other contributions to our other retirement benefit plans in 2004. We are currently evaluating the impact of the Pension Funding Equity Act enacted in 2004 on our projected funding. On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law. Benefit obligations and costs reported that are related to prescription drug coverage do not reflect the impact of this legislation. In addition, we are currently evaluating new accounting standards that become effective in the third quarter of 2004 that may require changes to previously reported benefit information and to our net benefit cost for the year ended December 31, 2004. 10. SEGMENT INFORMATION During 2004, El Paso reorganized its business structure into two primary business lines, regulated and unregulated. Historically, our operating segments included Pipelines, Production, Merchant Energy and Field Services. As a result of El Paso's reorganization, we renamed our Merchant Energy segment as our Power segment. All periods presented reflect this change in segments. Our regulated business consists of our Pipelines segment, while our unregulated businesses consist of our Production, Power and Field Services segments. Our segments are strategic business units that provide a variety of energy products and services. 19 They are managed separately as each segment requires different technology and marketing strategies. Our corporate operations include our general and administrative functions. Corporate also includes other unregulated operations, including our petroleum ship charter operations and various other contracts and assets, all of which are immaterial to our results in 2004 and do not constitute separate operating segments. During the first quarter of 2004, we reclassified our petroleum ship charter operations from discontinued operations to continuing corporate operations. During the second quarter of 2004, we reclassified our Canadian and certain other international natural gas and oil production operations from our Production segment to discontinued operations in our financial statements. Our operating results for all periods presented reflect these changes. We use earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business segments. We define EBIT as net income (loss) adjusted for (i) items that do not impact our income (loss) from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes, (ii) income taxes, (iii) interest and debt expense and (iv) distributions on preferred interests of consolidated subsidiaries. Our business operations consist of both consolidated businesses as well as substantial investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to more effectively evaluate the performance of all of our businesses and investments. Also, we exclude interest and debt expense and distributions on preferred interests of consolidated subsidiaries so that investors may evaluate our operating results without regard to our financing methods or capital structure. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow. Below is a reconciliation of our EBIT to our income from continuing operations for the periods ended June 30:

~~MARCH~~SIX ~~31,~~MONTHS ~~DECEMBER~~QUARTER 31ENDED ENDED JUNE 30, ~~2004~~JUNE ~~2003~~30, ------------- ----------- 2004 2003 2004 2003 ----- ----- ---- ---- (IN MILLIONS) ~~Regulated~~Total ~~Pipelines~~EBIT................................................ $179 ~~5,445~~$181 $309 ~~5,395~~$498 ~~Unregulated~~Interest ~~Production~~and debt expense................................~~...............~~ ~~2,366~~(91) 2(101) (192) (200) Affiliated interest income (expense),~~772~~ ~~Power~~net................~~....................................~~ ~~2,071~~5 ~~2,121~~(7) ~~Field~~(9) ~~Services~~(14) Distributions on preferred interests of consolidated subsidiaries........................................... ~~209 224~~ --~~-----~~ (7) --~~-----~~ ~~Total~~(14) ~~segment~~Income ~~assets~~taxes.................................. ~~10,091 10,512 Corporate~~...........~~.......................................~~ ~~436~~(32) ~~531~~(19) ~~Discontinued~~(37) ~~operations....................................~~(89) ~~157 1,366~~ ---- ---- ---- ---- ~~Total~~Income ~~consolidated~~from ~~assets~~continuing operations...................~~..........~~ $~~10,684~~ 61 $~~12,409~~ 47 $ 71 $181 ==== ==== ==== ====

The following tables reflect our segment results as of and for the periods ended June 30:

~~2004~~REGULATED ~~2003~~UNREGULATED --------- ----------------------------- FIELD QUARTER ENDED JUNE 30, PIPELINES PRODUCTION POWER SERVICES CORPORATE(1) TOTAL ---------------------- --------- ---------- ----- -------- ------------ ----- (IN MILLIONS) ~~Operating~~2004 ~~results~~Revenues ~~data:~~from ~~Operating~~external customers............ $189 $174(2) $45 $ 83 $ 14 $505 Intersegment revenues....................... -- 9 -- 1 (10) -- Operation and maintenance................... ~~$170~~54 ~~$193~~38 ~~Operating~~22 ~~expenses~~6 -- 120 Depreciation, depletion and amortization.... 30 80 2 1 2 115 Loss (gain) on long-lived assets............ -- -- (1) 1 -- -- Operating income............................ ~~116~~$ ~~133~~71 ~~Income~~$ 59 $ 6 $ 10 $ 2 $148 Earnings from ~~continuing~~unconsolidated ~~operations~~affiliates..... 17 -- 6 1 -- 24 Other income, net.................... ~~30 34 Net income(1)~~....... 1 -- 4 -- 2 7 ---- ---- --- ---- ---- ---- EBIT........................................ 30$ 3489 $ 59 $16 $ 11 $ 4 $179 ==== ==== === ==== ==== ====

~~2004~~REGULATED ~~2003~~UNREGULATED --------- ----------------------------- FIELD QUARTER ENDED JUNE 30, PIPELINES PRODUCTION POWER SERVICES CORPORATE(1) TOTAL ---------------------- --------- ---------- ----- -------- ------------ ----- (IN MILLIONS) ~~Operating~~2003 ~~revenues~~Revenues from external customers............ $209 $206(2) $71 $ 87 $ 10 $583 Intersegment revenues....................... -- 27 -- 12 (18) 21(3) Operation and maintenance....... ~~$193 $242 Cost of sales~~............ 58 45 21 6 2 132 Depreciation, depletion and amortization.... 27 87 3 2 2 121 Loss (gain) on long-lived assets............ (9) (5) -- (17) 1 (30) Operating income (loss)..................... 15$ 4089 ~~General,~~$ ~~administrative~~93 ~~and~~$31 ~~other~~$ ~~expenses~~27 $(12) $228 Earnings (losses) from unconsolidated affiliates................................ 3516 60(2) 12 (81) 1 (54) Other income, net........................... 1 2 1 -- 3 7 ---- ---- --- ---- ---- ---- EBIT........................................ 2$106 2$ 93 $44 $(54) $ (8) $181 ==== ==== === ==== ==== ====

~~2004~~REGULATED ~~2003~~UNREGULATED --------- ----------------------------- FIELD SIX MONTHS ENDED JUNE 30, PIPELINES PRODUCTION POWER SERVICES CORPORATE(1) TOTAL ------------------------- --------- ---------- ----- -------- ------------ ------ (IN MILLIONS) ~~Cash~~2004 ~~flows~~Revenues from ~~operating~~external ~~activities~~customers............ $426 $325(2) $ 99 $162 $ 30 $1,042 Intersegment revenues....................... -- 21 -- 1 (22) -- Operation and maintenance................... 113 77 45 12 -- 247 Depreciation, depletion and amortization.... 60 156 6 2 4 228 Loss on long-lived assets................... -- -- 87 1 -- 88 Operating income (loss)..................... $181 ~~336~~$104 $(74) ~~513~~$ ~~Cash~~21 ~~flows~~$ 5 $ 237 Earnings (losses) from ~~investing~~unconsolidated ~~activities~~affiliates................................ ~~111~~39 (~~276~~2) ~~Cash~~18 ~~flows~~4 -- 59 Other income, net........................... 1 -- 9 -- 3 13 ---- ---- ---- ---- ---- ------ EBIT........................................ $221 $102 $(47) $ 25 $ 8 $ 309 ==== ==== ==== ==== ==== ====== 2003 Revenues from ~~financing~~external ~~activities~~customers............ $502 $438(2) $130 $201 $ 18 $1,289 Intersegment revenues....................... (~~421~~1) 43 -- 25 (~~174~~29) 38(3) Operation and maintenance................... 116 80 48 15 2 261 Depreciation, depletion and amortization.... 55 170 7 4 6 242 Loss (gain) on long-lived assets............ (9) (5) -- (18) 1 (31) Operating income (loss)..................... $242 $196 $ 43 $ 39 $(20) $ 500 Earnings (losses) from unconsolidated affiliates................................ 39 1 27 (82) -- (15) Other income (expense), net................. (2) 2 6 -- 7 13 ---- ---- ---- ---- ---- ------ EBIT........................................ $279 $199 $ 76 $(43) $(13) $ 498 ==== ==== ==== ==== ==== ======

--------------- (1) Includes our Corporate activities, petroleum ship charter operations, various other contracts and assets and eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. We record an intersegment revenue elimination, which is the only elimination included in the "Corporate" column, to remove intersegment transactions. (2) Revenues from external customers include gains and losses related to our hedging of price risk associated with our natural gas and oil production. (3) Relates to intercompany activities between our continuing operations and our discontinued operations. 21 Total assets by segment are presented below:

JUNE 30, DECEMBER 31, 2004 2003 -------- ------------ (IN MILLIONS) Regulated Pipelines................................................... $5,486 56$ 5,395 Unregulated Production.................................................. ~~103~~2,198 ~~Other~~2,334 Power..................................................... 1,009 2,121 Field Services............................................ 9234 224 ------ ------- Total segment assets................................... 8,927 10,074 Corporate................................................... 353 531 Discontinued operations..................................... 165 1,804 ------ ------- Total consolidated assets.............................. $~~168~~9,445 $12,409 ====== =======

11. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS We hold investments in various unconsolidated affiliates which are accounted for using the equity method of accounting. The summarized financial information below includes our proportionate share of the operating results of our unconsolidated affiliates, including affiliates in which we hold a less than 50 percent interest as well as those in which we hold a greater than 50 percent interest.

~~2004~~QUARTER ~~2003~~ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, ----------------------------- ------------------------------ ~~(IN~~GREAT ~~MILLIONS)~~OTHER ~~Regulated~~GREAT ~~Businesses~~OTHER ~~Pipelines.................................................~~LAKES $INVESTMENTS ~~132~~TOTAL $LAKES ~~173~~INVESTMENTS ~~Unregulated~~TOTAL ~~Businesses~~----- ~~Production................................................~~----------- ~~(66) 109 Power..................................................... (63) 32 Field Services............................................ 14 11~~ ----- ----- ~~Segment EBIT........................................... 17 325 Corporate................................................... 4 (5)~~ ----------- ------ ~~Consolidated~~(IN ~~EBIT~~MILLIONS) ~~from~~2004 ~~continuing~~Operating ~~operations...........~~results 21data: ~~320~~Operating ~~Interest and debt expense~~revenues................~~...................~~ ~~(100)~~$32 ~~(99)~~$184 ~~Affiliated~~$216 ~~interest~~$68 ~~expense,~~$ ~~net~~318 $ 386 Operating expenses................~~............~~ ~~(14)~~13 ~~(7)~~156 ~~Distributions~~169 on26 ~~preferred~~259 ~~interests~~285 ofIncome ~~consolidated~~from ~~subsidiaries~~continuing operations.....................~~.........................~~ --11 ~~(7)~~5 ~~Income~~16 ~~taxes~~24 22 46 Net income(1).....................~~...........................~~ 3011 ~~(71)~~5 ~~-----~~16 ~~-----~~24 ~~Income~~22 ~~(loss)~~46 ~~from~~2003 ~~continuing~~Operating ~~operations~~results data: Operating revenues.................. ~~(63)~~$30 ~~136~~$176 ~~Discontinued~~$206 ~~operations,~~$65 ~~net~~$ of334 ~~income~~$ ~~taxes~~399 Operating expenses................ ~~(55)~~14 ~~(222)~~134 ~~Cumulative~~148 ~~effect~~28 of253 ~~accounting~~281 ~~changes,~~Income ~~net~~from ofcontinuing ~~income taxes~~operations.....................~~................................~~ --7 (12) ~~-----~~19 ~~-----~~20 33 53 Net ~~loss~~income(1).....................~~.............................~~ ~~$(118)~~7 $12 ~~(98)~~19 ~~=====~~20 ~~=====~~33 53

--------------- (1)Includes net income of $7 million and $2 million for the quarters ended June 30, 2004 and 2003, and $15 million and $9 million for the six months ended June 30, 2004 and 2003, related to our proportionate share of affiliates in which we hold a greater than 50 percent interest. Our income statement reflects our share of net earnings (losses) from unconsolidated affiliates, which includes income or losses directly attributable to the net income or loss of our equity investments as well as impairments and other adjustments. The table below reflects our earnings (losses) from unconsolidated affiliates for the periods ended June 30:

~~PIPELINES~~QUARTER ~~SEGMENT~~ENDED ~~RESULTS~~SIX ~~2004~~MONTHS ~~2003~~JUNE 30, ENDED JUNE 30, -------------- -------------- 2004 2003 2004 2003 ----- ----- ----- ----- (IN MILLIONS,) ~~EXCEPT~~Proportional ~~VOLUME~~share ~~AMOUNTS)~~of ~~Operating~~income ~~revenues~~of investees..............~~............................~~ $16 ~~237~~$ 19 $46 ~~292~~$ ~~Operating~~53 ~~expenses~~Impairment charges and gains and losses on sale of investments Dauphin Island/Mobile Bay impairment(1)..............~~............................~~ ~~(127)~~-- (~~139~~80) --~~-----~~ ~~-------~~(80) ~~Operating~~Other ~~income~~gains, net.....................................~~.....~~ ~~110~~3 ~~153~~1 ~~Other~~3 ~~income~~1 Other.................................................. 225 206 10 11 --- ---- --- ---- ~~EBIT~~Total earnings (losses) from unconsolidated affiliates...........................................~~...........~~ $24 ~~132~~$(54) $59 ~~173~~$(15) ===~~====~~ ====~~===~~ ~~Throughput volumes (BBtu/d)(1).............................. 8,901 9,831~~ ===~~====~~ ====~~===~~

--------------- (1) This impairment resulted from the anticipated sales of these investments, which were completed in the third quarter of 2004. 22 We received distributions and dividends from our investments of $23 million and $11 million for the quarters ended June 30, 2004 and 2003, and $47 million and $31 million for the six months ended June 30, 2004 and 2003. In January 2004, we also received $54 million of non-cash assets and liabilities as a liquidating distribution of our equity investment in Noric Holdings I, LLC. We did not recognize any gain or loss on this distribution. Related Party Transactions We enter into a number of transactions with our unconsolidated affiliates in the ordinary course of conducting our business. The following table shows the income statement impact of transactions with our affiliates for the periods ended June 30:

~~REVENUE~~QUARTER ~~EXPENSE~~ENDED ~~OTHER~~SIX ~~EBIT~~MONTHS ~~IMPACT~~JUNE 30, ENDED JUNE 30, ------------- --------------- 2004 2003 2004 2003 ----- ----- ------ ~~FAVORABLE/(UNFAVORABLE)~~------ (IN MILLIONS) ~~ANR~~Operating ~~Contract remarketing/restructuring with We Energies and other customers~~revenues........................................ $~~(20)~~212 $--338 $--405 $~~(20)~~580 ~~Termination~~Cost of ~~Dakota gasification facility contract~~sales...... ~~(16) 15 -- (1) 2003 charge related to a partial termination of a hedging obligation for Blue Lake Gas Storage Company~~........... ~~-- -- 4 4 CIG Storage facility gas loss replacement in 2004~~............. ~~-- (6) -- (6) Impact of the finalization of a rate case settlement in 2003~~..............~~.....................................~~ ~~(4)~~15 --29 --30 ~~(4)~~69 ~~OTHER~~General, ~~Lower~~administrative ~~recoveries~~and ofother ~~natural gas in excess of gas used on our systems~~expenses...............~~.............................~~ ~~(16)~~55 --78 --106 ~~(16)~~158 Other income.............................................~~........~~ 1 3 ~~(2)~~4 27 ~~----~~8 ~~---~~Reimbursement ~~---~~for ~~----~~operating ~~Total~~expenses.....................~~........................~~ ~~$(55)~~1 ~~$12~~-- $1 ~~2 $(41) ==== === === ====~~--

We are a party to a master hedging contract with El Paso Marketing, L.P., (EPM), a wholly-owned subsidiary of El Paso, which was formerly known as El Paso Merchant Energy L.P. Pursuant to that agreement, we hedge a portion of our natural gas production with EPM. Realized gains and losses on these hedges are included in operating revenues. Affiliated Receivables and Payables. We participate in El Paso's cash management program, which matches short-term cash surpluses and needs of its participating affiliates, thus minimizing total borrowing from outside sources. We have historically and consistently borrowed cash from El Paso under this program. As of June 30, 2004 and December 31, 2003, we had borrowed $32 million and $906 million. The interest rate as of June 30, 2004, and December 31, 2003, was 2.4% and 2.8%. In addition, we had a demand note receivable with El Paso of $326 million and $275 million at June 30, 2004 and December 31, 2003. The interest rate for this demand note receivable was approximately 2.1% at June 30, 2004 and 1.7% at December 31, 2003. At June 30, 2004, and December 31, 2003, we had current accounts and notes receivable from related parties of $110 million and $167 million. These balances were incurred in the normal course of our business. In addition, we had a non-current note receivable from a related party of $94 million and $127 million included in other non-current assets at June 30, 2004 and at December 31, 2003. At June 30, 2004, and December 31, 2003, we had other accounts payable to related parties of $88 million and $110 million. These balances were incurred in the normal course of business. Other. During the first quarter of 2004, Coastal Stock Company, our wholly-owned subsidiary, issued 68,000 shares of its Class A Preferred Stock to a subsidiary of El Paso for $71 million. We included the proceeds from the issuance of these shares as securities of subsidiaries in our balance sheet. 23 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information contained in Item 2 updates, and you should read it in conjunction with, information disclosed in our Annual Report on 2003 Form 10-K, and the financial statements and notes presented in Item 1 of this Quarterly Report on Form 10-Q. During the second quarter of 2004, we reclassified our historical Canadian and certain other international natural gas and oil production operations from our Production segment to discontinued operations in our financial statements for all periods presented. In addition, our results for the quarter and six months ended June 30, 2003 have been restated to reflect the accounting impact of a reduction in our historically reported proved natural gas and oil reserves as further discussed in our 2003 Annual Report on Form 10-K. LIQUIDITY AND CAPITAL RESOURCES LIQUIDITY We rely on cash generated from our internal operations and loans from El Paso, our direct parent, through its cash management program as our primary sources of liquidity, as well as proceeds from asset sales and capital contributions from El Paso. We expect that our future funding for working capital needs, capital expenditures and debt service will continue to be provided from some or all of these sources. Under El Paso's cash management program, we have historically and consistently borrowed cash. Currently, one of our subsidiaries, CIG, is not advancing funds to El Paso via the cash management program due to its anticipated cash needs. For a further discussion of our participation in El Paso's cash management program, see Item 1, Financial Statements, Note 11. During 2004, El Paso restated its historical financial statements to reflect the accounting impact of revisions to its natural gas and oil reserve estimates and changes in the manner in which it accounted for certain derivative contracts, primarily those related to the hedging of its natural gas production. El Paso received several waivers based on its belief that the restatements would cause a delay in filing its financial statements and would have constituted various events of default under its then existing revolving credit facility and various other financing transactions. El Paso subsequently filed its financial statements within the time frames granted by these waivers. In November 2004, El Paso entered into a new credit agreement with a group of lenders for an aggregate of $3 billion in financings to replace its previous revolving credit facility which was scheduled to mature in June 2005. Upon closing of the new credit agreement, El Paso borrowed $1.25 billion and used approximately $1.2 billion of capacity to support existing letters of credit under its previous revolving credit facility. Our subsidiaries, ANR and CIG, continue to be eligible borrowers under the new credit agreement. Additionally, our interests in ANR, CIG, WIC, and ANR Storage Company are pledged as collateral under the new credit agreement. For a further discussion of El Paso's new credit agreement and other information regarding our financing obligations, see Item 1, Financial Statements, Note 7. Additionally, under several of our financing arrangements, we are required to file financial statements in a timely manner. We have not yet filed our financial statements for the third quarter of 2004; however, no notice has been given as to any violations under these financing arrangements for our failure to file financial statements. We believe that we will file our financial statements prior to any notice being given or within the allowed time frames under these arrangements such that there will be no event of default. For a discussion of risks that may impact our business, see our 2003 Annual Report on Form 10-K. We believe we will be able to meet our ongoing liquidity and cash needs through a combination of sources, including cash on hand, cash generated from our operations, proceeds from asset sales, financing activities and advances from El Paso. However, a number of factors could influence our liquidity sources, as well as the timing and ultimate outcome of our ongoing efforts and plans, which are discussed in our 2003 Annual Report on Form 10-K. 24 OVERVIEW OF CASH FLOW ACTIVITIES FOR THE SIX MONTHS ENDED JUNE 30, 2004 AND 2003 For the six months ended June 30, 2004 and 2003, our cash flows from continuing operations are summarized as follows:

~~PRODUCTION SEGMENT RESULTS~~ 2004 2003 -----~~---------------------~~ -----~~---~~ ~~--------~~ (IN MILLIONS~~, EXCEPT VOLUMES AND PRICES~~) ~~Operating~~Cash ~~revenues:~~flows ~~Natural~~from gas............................................... $ 150 $ 224 Oil, condensate and liquids............................... 38 47 Other..................................................... 2 2 ------ ------ Total operating ~~revenues~~activities.......................... 190 273 Transportation and net product costs........................ (8) (13) ------ ------ Total operating margin............................ 182 260 Other operating expenses Depreciation, depletion and amortization.................. (85) (91) Production costs(1)....................................... (23) (31) Loss on long-lived assets and ceiling test charges........ (121) (10) General and administrative expenses....................... (17) (21) Taxes, other than production and income taxes............. -- (1) ------ ------ Total other operating expenses(2)................. (246) (154) ------ ------ Operating income (loss)................................... (64) 106 Other income (expense)...................................... (2) 3 ------ ------ EBIT...................................................... $ ~~(66)~~452 $ ~~109~~931 ~~======~~Cash ~~======~~flows ~~Volumes,~~from ~~prices~~investing ~~and costs per unit: Natural gas Volumes (MMcf)~~activities........................~~.................~~ ~~29,469 42,311 ====== ====== Average realized prices including hedges~~ (~~$/Mcf~~142)~~(3)....~~ ~~$ 5.09 $ 5.30 ====== ====== Average realized prices excluding hedges~~ (~~$/Mcf~~534)~~(3)....~~ $Cash ~~5.59~~flows $from ~~6.62~~financing ~~====== ====== Average transportation costs ($/Mcf)~~activities................... ~~$ 0~~.~~23 $ 0~~.~~22 ====== ====== Oil, condensate and liquids Volumes (MBbls)~~...~~.....................................~~ ~~1,256 1,723 ====== ====== Average realized prices including hedges~~ (~~$/Bbl~~374)~~(3)....~~ ~~$30.71 $27.28 ====== ====== Average realized prices excluding hedges~~ (~~$/Bbl~~346)(3).... $30.71 $27.29 ====== ====== Average transportation costs ($/Bbl)................... $ 1.05 $ 0.88 ====== ====== Production cost ($/Mcfe) Average lease operating costs.......................... $ 0.64 $ 0.36 Average production taxes............................... (0.03) 0.24 ------ ------ Total production cost(1).......................... $ 0.61 $ 0.60 ====== ====== Average general and administrative expense ($/Mcfe)......... $ 0.47 $ 0.41 ====== ====== Unit of production depletion cost ($/Mcfe).................. $ 2.17 $ 1.62 ====== ======

Cash from Continuing Operating Activities Net cash generated from our continuing operating activities was $452 million during the first six months of 2004 versus $931 million during the same period in 2003. In our operating activities, we experienced a $479 million decline in 2004 in cash generated from our operations primarily as a result of sales of operating assets during both 2003 and 2004 and the effects of lower capital spending in our Production segment. Cash from Continuing Investing Activities Net cash used by our continuing investing activities was $142 million for the six months ended June 30, 2004, due to $296 million in capital expenditures partially offset by $81 million of proceeds from the sale of assets and investments and $34 million of returns of restricted cash. Our capital expenditures for the six months ended June 30, 2004 included the following (in millions):

~~VARIANCE --------------------------------- PRODUCTION REVENUE VARIANCE ANALYSIS PRICES VOLUMES HEDGES TOTAL ------------------------------------ ------ ------- ------ ----- (IN MILLIONS) Natural gas~~Pipelines................................................... $~~(31)~~161 ~~$(85)~~Production.................................................. ~~$42~~133 ~~$(74) Oil, condensate and liquids~~Other....................................................... 42 ~~(13)~~ -- ~~(9)~~ ---- ~~---- --- ----~~ Total ~~operating revenues~~.................................................. $~~(27)~~296 ~~$(98) $42 $(83)~~ ==== ~~==== === ====~~

From July through October 2004, we have spent approximately $259 million for our Pipelines segment and approximately $107 million for our Production segment. Cash from Continuing Financing Activities Net cash used in our continuing financing activities for the six months ended June 30, 2004 primarily consisted of payments on affiliated notes payable of $896 million and payments to retire long-term debt and other financing obligations of $460 million. Offsetting these uses of cash were the proceeds received from El Paso primarily related to the issuance of the preferred stock of Coastal Stock Company, our wholly-owned subsidiary and $907 million of cash contributed by our discontinued operations as further discussed below. We reflect the net cash generated by our discontinued operations as a cash inflow to our continuing financing activities. Cash from Discontinued Operations During the first six months of 2004, our discontinued operations contributed $0.9 billion of cash. We generated $0.1 billion in cash in these operations, received proceeds from the sales of the Eagle Point and Aruba refineries of approximately $1.2 billion and repaid long-term debt of $0.4 billion related to the Aruba refinery. 25 SEGMENT RESULTS Below are our results of operations (as measured by EBIT) by segment. During 2004, El Paso reorganized its business structure into two primary business lines, regulated and unregulated. Historically, our operating segments included Pipelines, Production, Merchant Energy and Field Services. As a result of El Paso's reorganization, we renamed our Merchant Energy segment as our Power segment. All periods presented reflect this change in segments. Our regulated business consists of our Pipelines segment, while our unregulated businesses consist of our Production, Power and Field Services segments. Our segments are strategic business units that provide a variety of energy products and services. They are managed separately as each segment requires different technology and marketing strategies. Our corporate activities include our general and administrative functions. Corporate also includes other unregulated activities, including our petroleum ship charter operations and various other contracts and assets, all of which are immaterial to our results in 2004 and do not constitute separate operating segments. During the first quarter of 2004, we reclassified our petroleum ship charter operations from discontinued operations to our continuing corporate operations. During the second quarter of 2004, we reclassified our Canadian and certain other international natural gas and oil production operations from our Production segment to discontinued operations in our financial statements. Our operating results for all periods presented reflect these changes. We use earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business segments. We define EBIT as net income (loss) adjusted for (i) items that do not impact our income (loss) from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes, (ii) income taxes, (iii) interest and debt expense and (iv) distributions on preferred interests of consolidated subsidiaries. Our business operations consist of both consolidated businesses as well as substantial investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to more effectively evaluate the performance of all of our businesses and investments. Also, we exclude interest and debt expense and distributions on preferred interests of consolidated subsidiaries so that investors may evaluate our operating results without regard to our financing methods or capital structure. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow. Below is a reconciliation of our consolidated EBIT to our consolidated net income (loss) for the periods ended June 30:

~~POWER~~QUARTER ~~SEGMENT~~ENDED ~~RESULTS~~SIX ~~2004~~MONTHS ~~2003~~JUNE 30, ENDED JUNE 30, -------------- --------------- 2004 2003 2004 2003 ----- ------ ----- ------- (IN MILLIONS) ~~Gross~~Regulated ~~margin(1)~~Businesses Pipelines................................................. $ 3589 $ 106 $ 221 $ 279 Unregulated Businesses Production................................................ 59 93 102 199 Power..................................................... 16 44 ~~Operating~~(47) ~~expenses~~76 Field Services............................................ 11 (~~115~~54) 25 (3243) ---- ----- ----- ~~Operating~~------- ~~loss~~Segment EBIT............................................ 175 189 301 511 Corporate................................................... 4 (808) 128 ~~Other~~(13) ---- ----- ----- ------- Consolidated EBIT from continuing operations............ 179 181 309 498 Interest and debt expense................................... (91) (101) (192) (200) Affiliated interest income (expense), net................... 5 (7) (9) (14) Distributions on preferred interests of consolidated subsidiaries.............................................. 17-- 20(7) -- (14) Income taxes................................................ (32) (19) (37) (89) ---- ----- ~~EBIT~~----- ------- Income from continuing operations......................... 61 47 71 181 Discontinued operations, net of income taxes................ (11) (931) (139) (1,151) Cumulative effect of accounting changes, net of income taxes..................................................... -- -- -- (12) ---- ----- ----- ------- Net income (loss)......................................... $ 50 $(63884) $ 32(68) $ (982) ==== ===== ===== =======

26 The following is a discussion of the comparative quarterly and six month period results of each of our business segments; our corporate activities; interest and debt expense; affiliated interest income (expense); net, distributions on preferred interests of consolidated subsidiaries; income taxes; and the results of our discontinued operations. REGULATED BUSINESSES -- PIPELINES SEGMENT Our Pipelines segment owns and operates our interstate natural gas transmission businesses. For a further discussion of the business activities of our Pipelines segment, see our 2003 Annual Report on Form 10-K. Below are the operating results and analysis of these results for our Pipelines segment for the periods ended June 30:

~~FIELD~~QUARTER ~~SERVICES~~ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ---------------- ---------------- PIPELINES SEGMENT RESULTS 2004 2003 2004 2003 ------------------------- ------ ------ ------ ------ (IN MILLIONS), ~~Processing~~EXCEPT ~~and~~VOLUME ~~gathering~~AMOUNTS) ~~gross~~Operating ~~margins(1)~~revenues................... ~~$ 20 $ 24 Operating expenses~~........... $ 189 $ 209 $ 426 $ 501 Operating expenses............................... (9118) (12120) (245) (259) ------ ------ ------ ------ Operating income..............................~~............~~ 1171 1289 181 242 Other income ~~(expense)~~...................................... 318 ~~(1)~~17 40 37 ------ ------ ------ ------ EBIT.......................................... $ 89 $ 106 $ 221 $ 279 ====== ====== ====== ====== Throughput volumes (BBtu/d)(1).................. $7,654 147,520 $8,278 118,670 ====== ====== ====== ======

--------------- (1) Throughput volumes exclude intrasegment activities. Operating Results (EBIT) The following factors contributed to our overall EBIT decrease of $17 million and $58 million for the quarter and six months ended June 30, 2004 as compared to the same periods ended June 30, 2003:

~~FIELD~~QUARTER ~~SERVICES~~ENDED ~~SEGMENT~~JUNE ~~RESULTS~~30, ~~2004~~SIX ~~2003~~MONTHS ENDED JUNE 30, --------------------------------------- --------------------------------------- REVENUE EXPENSE OTHER EBIT IMPACT REVENUE EXPENSE OTHER EBIT IMPACT ------- ~~(IN~~------- ~~MILLIONS)~~----- ~~Volumes~~----------- ~~and~~------- ~~Prices:~~------- ~~Processing~~----- ~~Volumes~~----------- ~~(BBtu~~FAVORABLE/d(UNFAVORABLE) (IN MILLIONS) ANR Dakota contract termination....... $(12) $ 12 $ -- $ -- $(28) $ 27 $ -- $ (1) Contract remarketing/restructurings...... (6) -- -- (6) (26) -- -- (26) CIG Table Rock facility sold in 2003............................ ~~1,688~~-- ~~1,703~~(6) ~~======~~-- ~~======~~(6) ~~Prices~~-- (~~$/MMBtu~~6) -- (6) Storage facility gas loss replacement in 2004............. -- -- -- -- -- (6) -- (6) Change to regulated depreciation method.......................... $-- ~~0.12~~(2) $-- ~~0.12~~(2) ~~======~~-- ~~======~~(4) ~~Gathering~~-- ~~Volumes~~ (~~inlet BBtu/d~~4) OTHER Fuel recoveries, net of gas used............................~~.....~~ 19(4) ~~200~~-- ~~======~~-- ~~======~~(4) ~~Prices~~(20) -- -- (~~$/MMBtu~~20) Other............................. 2 (2) 1 1 (1) 3 3 5 ---- ---- ---- ---- ---- ---- ---- ---- Total...................... $(20) ~~0.04~~$ 2 $ ~~0.22~~1 $(17) $(75) $ 14 $ 3 $(58) ==== ==== ==== ==== ==== ==== ==== ====

The renegotiation or restructuring of several contracts on our pipeline systems, including our contracts with We Energies, will continue to unfavorably impact our operating results and EBIT for the remainder of 2004, among other items noted below. Guardian Pipeline, which is owned in part by We Energies, is currently providing a portion of its firm transportation requirements and directly competes with ANR for a portion of the markets in Wisconsin. Additionally, ANR will continue to experience lower operating revenues and lower operating expenses for the remainder of 2004 based on the termination of the Dakota gasification facility contract on its system. However, the termination of this contract will not have a significant overall impact on operating income and EBIT. Finally, ANR has entered into an agreement with a shipper to restructure 27 another of its transportation contracts on its Southeast Leg as well as a related gathering contract. We anticipate this restructuring will be completed in March 2005 upon which ANR will receive approximately $26 million, at which time this amount will be reflected in earnings. In November 2004, the FERC issued an industry-wide Proposed Accounting Release that, if enacted as written, will disallow the capitalization of certain costs that are part of our pipeline integrity program. The accounting release is proposed to be effective January 2005 following a period of public comment on the release. We are currently reviewing the release and have not determined what impact, if any, this release will have on our consolidated financial statements. UNREGULATED BUSINESSES -- PRODUCTION SEGMENT Our Production segment conducts our natural gas and oil exploration and production activities. Our operating results are driven by a variety of factors including the ability to locate and develop economic natural gas and oil reserves, extract those reserves with minimal production costs and sell the products at attractive prices. El Paso's long-term strategy for us includes developing our production opportunities primarily in the U.S. and Brazil, while currently divesting our production properties outside of these areas. As of November 2004, we have sold all of our Canadian operations and substantially all of our operations in Indonesia. Beginning in the second quarter of 2004, these operations have been treated as discontinued operations as further discussed in Item 1, Financial Statements, Note 3. All periods reflect this change. Production and Capital Expenditures For the six months ended June 30, 2004, our total equivalent production has declined approximately 31 Bcfe or 32 percent as compared to the same period in 2003 primarily due to normal production declines, asset sales and disappointing drilling results. Our average daily production through October 2004 has been as follows: ~~January-October 2004........................................ 339 MMcfe/d Month of October 2004....................................... 301 MMcfe/d~~

Our year to date 2004 and October 2004 production levels were negatively impacted by hurricanes that occurred in September 2004 in the Gulf of Mexico. The hurricanes caused us to shut-in production and also caused damage to third party facilities that transport our production. We continue to experience reduced production levels in our offshore Gulf of Mexico operations as a result of the damage to third party facilities and do not expect these facilities to return to full production until mid-2005. Our future production levels are dependent upon the amount of capital allocated to us, the level of success in our drilling programs and future asset sales or acquisitions. Through October 31, 2004, we have spent $240 million in capital expenditures for acquisition, exploration, and development activities. Based on the results to date of our 2004 drilling program, we expect our domestic unit of production depletion rate to increase from $2.32 per Mcfe during the second quarter of 2004 to $2.48 per Mcfe for the third quarter of 2004 and to $2.68 per Mcfe for the fourth quarter of 2004. Production Hedging We primarily conduct our hedging activities with EPM, our affiliate, through natural gas and oil derivatives on our natural gas and oil production to stabilize cash flows and reduce the risk of downward commodity price movements on our sales. Because this hedging strategy only partially reduces our exposure to downward movements in commodity prices, our reported results of operations, financial position and cash flows can be impacted significantly by movements in commodity prices from period to period. For a further discussion of our hedging program, refer to our 2003 Annual Report on Form 10-K. 28 Operating Results Below are the operating results and analysis of these results for each of the periods ended June 30:

QUARTER ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------ ------------------ PRODUCTION SEGMENT RESULTS 2004 2003 2004 2003 -------------------------- ------- ------- ------- ------- (IN MILLIONS, EXCEPT VOLUMES AND PRICES) ~~Gross~~Operating ~~margin~~revenues: Natural gas............................... $ 148 $ 196 $ 273 $ 399 Oil, condensate and liquids............... 35 30 72 73 Other..................................... $-- 57 $1 9 ------- ------- ------- ------- Total operating revenues.......... 183 233 346 481 Transportation and net product costs........ (52) (7) (7) (20) ------- ------- ------- ------- Total operating margin............ 181 226 339 461 Operating expenses: Depreciation, depletion and amortization........................... (80) (87) (156) (170) Production costs(1)....................... (222) (330) (43) (57) Gain on long-lived assets................. -- 5 --- ~~Operating~~5 ~~income~~General and administrative expenses....... (~~loss~~20) (21) (36) (42) Taxes, other than production and income taxes.................................. -- -- -- (1) ------- ------- ------- ------- Total operating expenses(2)....... 3(122) (8133) ~~Other~~(235) (265) ------- ------- ------- ------- Operating income.......................... 59 93 104 196 Other income (expense)...................... 1-- -- (2) 3 ------- ------- ------- ------- EBIT...................................... $ 59 $ 93 $ 102 $ 199 ======= ======= ======= ======= Volumes, prices and costs per unit: Natural gas Volumes (MMcf)......................... 26,099 40,131 50,874 78,575 ======= ======= ======= ======= Average realized prices including hedges ($/Mcf)(3).................... $ 5.65 $ 4.91 $ 5.37 $ 5.08 ======= ======= ======= ======= Average realized prices excluding hedges ($/Mcf)(3).................... $ 5.99 $ 5.25 $ 5.83 $ 5.97 ======= ======= ======= ======= Average transportation costs ($/Mcf)... $ 0.05 $ 0.14 $ 0.09 $ 0.18 ======= ======= ======= ======= Oil, condensate and liquids Volumes (MBbls)........................ 1,062 1,188 2,260 2,779 ======= ======= ======= ======= Average realized prices including hedges ($/Bbl)(3).................... $ 33.17 $ 25.16 $ 31.81 $ 26.20 ======= ======= ======= ======= Average realized prices excluding hedges ($/Bbl)(3).................... $ 33.17 $ 25.16 $ 31.81 $ 26.20 ======= ======= ======= ======= Average transportation costs ($/Bbl)... $ 1.26 $ 0.72 $ 1.18 $ 0.84 ======= ======= ======= =======

QUARTER ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------ ------------------ PRODUCTION SEGMENT RESULTS 2004 2003 2004 2003 -------------------------- ------- ------- ------- ------- (IN MILLIONS, EXCEPT VOLUMES AND PRICES) ~~Long-term~~Production ~~debt,~~cost ~~including~~($/Mcfe) ~~current~~Average ~~maturities~~lease operating costs.......... $ 0.59 $ 0.~~....~~50 $~~103~~ 0.63 $99 ~~Other~~0.40 ~~interest~~Average production taxes............... 0.10 0.13 0.03 0.19 ------- ------- ------- ------- Total production cost............. $ 0.69 $ 0.63 $ 0.66 $ 0.~~..........~~59 --======= 3======= ~~Capitalized~~======= ~~interest~~======= Average general and administrative expenses ($/Mcfe).................................. $ 0.60 $ 0.44 $ 0.56 $ 0...44 ~~(3)~~======= ~~(3)~~======= ~~----~~======= ~~---~~======= ~~Total~~Unit ~~interest~~of ~~and~~production ~~debt~~depletion ~~expense~~cost ($/Mcfe).................................. $~~100~~ 2.32 $99 1.74 $ 2.29 $ 1.70 ======= ======= ======= =======

--------------- (1) Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes). (2) Transportation costs are included in operating expenses on our consolidated statements of income. (3) Prices are stated before transportation costs. Quarter Ended June 30, 2004 Compared to Quarter Ended June 30, 2003 EBIT. For the quarter ended June 30, 2004, EBIT was $34 million lower than the same period in 2003. The decrease in EBIT was primarily due to lower production volumes due to normal production declines and disappointing drilling results. Partially offsetting these decreases were higher natural gas and oil prices and lower operating expenses. Operating Revenues. The following table describes the variance in revenue between the quarters ended June 30, 2004 and 2003 due to: (i) changes in average realized market prices excluding hedges, (ii) changes in production volumes, and (iii) the effects of hedges.

~~2004~~VARIANCE ~~2003~~--------------------------------- PRODUCTION REVENUE VARIANCE ANALYSIS PRICES VOLUMES HEDGES TOTAL ------------------------------------ ------ ~~(IN~~------- ~~MILLIONS,~~------ ~~EXCEPT~~----- ~~FOR~~(IN ~~RATES~~MILLIONS) ~~Income~~Natural ~~taxes~~gas................................................. $ 20 $(3073) $71 ~~Effective~~5 ~~tax~~$(48) ~~rate~~Oil, condensate and liquids................................. 8 (3) -- 5 ---- ---- --- ---- $ 28 $(76) $ 5 $(43) ==== ==== === Other....................................................... ~~32%~~(7) ~~34%~~---- Total operating revenue variance.......................... $(50) ====

For the quarter ended June 30, 2004, operating revenues were $50 million lower than the same period in 2003 primarily due to lower production volumes, partially offset by higher natural gas and oil prices. The decline in production volumes was primarily due to normal production declines, particularly in our Texas Gulf Coast region, and disappointing drilling results. Average realized natural gas prices for the second quarter of 2004, excluding hedges, were $0.74 per Mcf higher than the same period in 2003, an increase of 14 percent. In addition, our natural gas hedging losses decreased from $14 million in 2003 to $9 million in 2004. We expect to continue to incur hedging losses in 2004. Operating Expenses. Total operating expenses were $11 million lower for the second quarter of 2004 as compared to the same period in 2003 primarily due to lower depreciation, depletion, and amortization expense and lower production costs, partially offset by a $5 million gain on the sale of non-full cost pool assets in 2003. Total depreciation, depletion, and amortization expense decreased by $7 million in the second quarter of 2004 as compared to the same period in 2003. Lower production volumes in 2004 due to the production declines discussed above reduced our depreciation, depletion, and amortization expense by $26 million. Partially offsetting this decrease were higher depletion rates due to higher finding and development costs which contributed an increase of $19 million. 30 Production costs decreased by $8 million in the second quarter of 2004 as compared to the same period in 2003 due to a decrease in lease operating costs and production taxes as a result of the lower production volumes in 2004 compared to 2003. On a per Mcfe basis, production taxes decreased $0.03 in 2004. However, our total production costs per Mcfe increased $0.06 as lease operating expenses increased $0.09 per Mcfe due to the lower production volumes discussed above. General and administrative expenses decreased $1 million in the second quarter of 2004 as compared to the same period in 2003. While total general and administrative costs remained relatively unchanged from period to period, the cost per unit increased $0.16 per Mcfe due to lower production volumes. For the remainder of 2004, we will have higher allocated expenses. Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003 EBIT. For the six months ended June 30, 2004, EBIT was $97 million lower than the same period in 2003. The decrease in EBIT was primarily due to lower production volumes due to normal production declines, asset sales and disappointing drilling results. Partially offsetting these decreases were lower operating expenses and decreased losses in 2004 from our hedging program. Operating Revenues. The following table describes the variance in revenue between the six months ended June 30, 2004 and 2003 due to: (i) changes in average realized market prices excluding hedges, (ii) changes in production volumes, and (iii) the effects of hedges.

For the six months ended June 30, 2004, operating revenues were $135 million lower than the same period in 2003 primarily due to lower production volumes and lower natural gas prices, partially offset by a decrease in our hedging losses. The decline in production volumes was primarily due to normal production declines, particularly in our Texas Gulf Coast region, the sale of properties in New Mexico as well as disappointing drilling results. Average realized natural gas prices for 2004, excluding hedges, were $0.14 per Mcf lower than the same period in 2003, a decrease of two percent. However, more than offsetting the decrease in revenues due to lower natural gas prices were $24 million of hedging losses in 2004 compared to $70 million in 2003 relating to our natural gas hedge positions. We expect to continue to incur hedging losses in 2004. Operating Expenses. Total operating expenses were $30 million lower in 2004 as compared to the same period in 2003 primarily due to lower depreciation, depletion, and amortization expense, lower production costs and lower general and administrative expenses, partially offset by a $5 million gain on the sale of non-full cost pool assets in 2003. Total depreciation, depletion, and amortization expense decreased by $14 million in 2004 as compared to the same period in 2003. Lower production volumes in 2004 due to asset sales and other production declines discussed above reduced our depreciation, depletion, and amortization expenses by $52 million. Partially offsetting this decrease were higher depletion rates due to higher finding and development costs which contributed an increase of $38 million. Production costs decreased by $14 million in 2004 as compared to the same period in 2003 primarily due to a decrease in production taxes resulting from high cost gas well tax credits in 2004 and due to lower production volumes in 2004 compared to 2003. On a per Mcfe basis, production taxes decreased $0.16 in 2004. 31 However, our total production costs per Mcfe increased $0.07 as lease operating expenses increased $0.23 per Mcfe due to the lower production volumes discussed above. General and administrative expenses decreased by $6 million in 2004 as compared to the same period in 2003. The decrease was primarily due to lower allocated expenses. However, our costs per unit increased $0.12 per Mcfe due to the lower production volumes. For the remainder of 2004, we will have higher allocated expenses. UNREGULATED BUSINESSES -- POWER SEGMENT Our Power segment includes the ownership and operation of domestic and international power generation facilities as well as the management of restructured power contracts. Below are the operating results and an analysis of these results for our Power segment for the periods ended June 30:

--------------- (1) Gross margin consists of revenues from our power plants and the initial net gains and losses incurred in connection with the restructuring of power contracts, as well as the subsequent revenues, cost of electricity purchases and changes in fair value of those contracts. The cost of fuel used in the power generation process is included in operating expenses. Quarter Ended June 30, 2004 Compared to Quarter Ended June 30, 2003 For the quarter ended June 30, 2004, our EBIT was $28 million lower than the same period in 2003. The decrease was primarily due to a $16 million decrease in equity earnings from our investment in Midland Cogeneration Venture due to higher natural gas costs to run the power plant. Also contributing to the decrease in EBIT was a 2003 reduction of $8 million of estimated costs associated with our power contract restructuring activities and an $8 million gain in 2003 on the termination of a steam contract at our Fulton power plant. We had previously recorded a liability related to our obligations under this steam contract. Partially offsetting these decreases were higher equity earnings of $6 million from two of our Asian equity investments in 2004 compared to the same period in 2003 and a $3 million gain on the sale of our equity investment in the Bastrop power facility in 2004. Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003 For the six months ended June 30, 2004, our EBIT was $123 million lower than the same period in 2003. The decrease was primarily due to the sale of Utility Contract Funding and its restructured power contract and related debt, which resulted in an $89 million impairment loss in 2004 included in operating expenses. Also contributing to the decrease in EBIT was a $22 million decrease in equity earnings from our investment in Midland Cogeneration Venture, an $8 million gain in 2003 on the termination of a steam contract at our Fulton power plant, and an $8 million reduction of estimated power contract restructuring costs in 2003. Partially offsetting these decreases were higher equity earnings of $8 million from two of our Asian equity investments and a $3 million gain on the sale of Bastrop in 2004. We currently anticipate selling a number of our domestic and international power assets. As these sales occur or as agreements are negotiated, we may incur future losses if the sales proceeds are less than the carrying value of the assets, and these losses may be significant. 32 UNREGULATED BUSINESSES -- FIELD SERVICES SEGMENT Our Field Services segment conducts our midstream activities, which include gathering and processing of natural gas. Our assets principally consist of our processing plants in south Louisiana. Below are the operating results and analysis of these results for our Field Services segment for the periods ended June 30:

--------------- (1) Gross margins consist of operating revenues less cost of products sold. We believe this measurement is more meaningful for understanding and analyzing our operating results because commodity costs play such a significant role in the determination of profit from our midstream activities. For the quarter and six months ended June 30, 2004, our EBIT was $65 million and $68 million higher than the same periods in 2003. Below is a summary of significant factors affecting EBIT.

--------------- (1) Our equity investments in Dauphin Island and Mobile Bay were impaired in 2003 based on anticipated losses on the sales of these investments, which were completed in the third quarter of 2004. 33 CORPORATE, NET Our corporate operations include our general and administrative functions. Corporate also includes other unregulated activities, including our petroleum ship charter operations and various other contracts and assets, all of which are immaterial to our results in 2004 and do not constitute separate operating segments. During the first quarter of 2004, we reclassified our petroleum ship charter operations from discontinued operations to our continuing corporate operations. Our operating results for all periods reflect this change. Below are the operating results and analysis of these results for our corporate operations for the periods ended June 30: CORPORATE RESULTS

Quarter Ended June 30, 2004 Compared to Quarter Ended June 30, 2003 For the quarter ended June 30, 2004, our EBIT increased by $12 million as compared to the same period in 2003 primarily due to $9 million of losses in 2003 on a gas supply contract with EPM, our affiliate, that was terminated in 2003. Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003 For the six months ended June 30, 2004, our EBIT increased by $21 million as compared to the same period in 2003 primarily due to $13 million of losses in 2003 on a gas supply contract with EPM, our affiliate, that was terminated in 2003. Also contributing to the increase was a $7 million increase in EBIT earned on our petroleum ship charters during 2004 that resulted from increased demand for those charter services. INTEREST AND DEBT EXPENSE Interest and debt expense for the quarter and six months ended June 30, 2004, was $10 million and $8 million lower than the same periods in 2003. Below is an analysis of our interest expense for the periods ended June 30:

Quarter and Six Months Ended June 30, 2004 Compared to Quarter and Six Months Ended June 30, 2003 Interest expense on long term debt decreased primarily due to retirements of debt during 2003 and 2004. Partially offsetting this decrease was the reclassification of our Coastal Finance I mandatorily redeemable preferred securities to long-term debt as a result of the adoption of SFAS No. 150 in 2003. Based on this reclassification, we began recording the preferred returns on these securities as interest expense rather than as 34 distributions on preferred interests. Other interest decreased due to the retirements of other financing obligations. AFFILIATED INTEREST INCOME (EXPENSE), NET Affiliated interest income (expense), net for the quarter ended June 30, 2004 was $12 million lower than the same period in 2003. The decrease was primarily due to lower average advances payable to El Paso under our cash management program in 2004, partially offset by higher average short-term interest rates. The average advances balance for the second quarter decreased from a net liability of $2.3 billion in 2003 to a net asset of $0.1 billion in 2004. The decrease in advances includes a $1.5 billion contribution from El Paso. However, the average short-term interest rate for the second quarter increased from 1.3% in 2003 to 2.3% in 2004. Affiliated interest expense, net for the six months ended June 30, 2004 was $5 million lower than the same period in 2003. The decrease was primarily due to lower average advances payable to El Paso under our cash management program in 2004, partially offset by higher average short-term interest rates. The average advances payable balance for the six months decreased from $2.1 billion in 2003 to $0.5 billion in 2004. The decrease in advances includes a $1.5 billion contribution from El Paso. However, the average short-term interest rate for the six months increase from 1.4% in 2003 to 2.5% in 2004. DISTRIBUTIONS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES Distributions on preferred interests of consolidated subsidiaries for the quarter and six months ended June 30, 2004, were $7 million and $14 million lower than the same periods in 2003 primarily due to the reclassification of our Coastal Finance I mandatorily redeemable preferred securities to long-term financing obligations as a result of the adoption of SFAS No. 150 in 2003. Based on this reclassification, we began recording the preferred returns on these securities as interest expense rather than as distributions on preferred interests. Also contributing to the decrease was the redemption of the preferred stock of Coastal Securities Company Limited. INCOME TAXES Income taxes included in our income from continuing operations and our effective tax rates for the periods ended June 30 were as follows:

Our effective tax rates were different than the statutory tax rate of 35 percent primarily due to: - state income taxes, net of federal income tax benefit; - foreign income taxed at different rates. DISCONTINUED OPERATIONS The loss from our discontinued operations for the second quarter of 2004 was $11 million compared to a loss of $931 million for the same period of 2003. The 2004 loss primarily relates to operating losses and general and administrative expenses in our remaining petroleum markets operations during the second quarter of 2004. The loss in 2003 was primarily due to impairments at our Aruba refining facility that was approved for sale by El Paso's Board of Directors during the second quarter of 2003. For the six months ended June 30, 2004, the loss from our discontinued operations was $139 million compared to a loss of $1,151 million during the same period in 2003. In 2004, $69 million of losses from 35 discontinued operations related to our Canadian and certain other international production operations, primarily from losses on asset sales and impairments, and $70 million was from our petroleum markets activities, primarily related to losses on the completed sales of our Eagle Point and Aruba refineries along with other operational and severance costs. The losses in 2003 related to impairment charges on our Aruba and Eagle Point refineries and on chemical assets, all as a result of the decision by El Paso's Board of Directors to exit and sell these businesses. COMMITMENTS AND CONTINGENCIES See Item 1, Financial Statements, Note 8, which is incorporated herein by reference. 36 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS We have made statements in this document that constitute forward-looking statements, as that term is defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements include information concerning possible or assumed future results of operations. The words "believe," "expect," "estimate," "anticipate" and similar expressions will generally identify forward-looking statements. These statements may relate to information or assumptions about: - capital and other expenditures; - dividends; - financing plans; - capital structure; - liquidity and cash flow; - credit ratings; - pending legal proceedings, claims and governmental proceedings, including environmental matters; - future economic performance; - operating income; - management's plans; and - goals and objectives for future operations. Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these variances can be material, depending upon the circumstances. We cannot assure you that the statements of expectation or belief contained in the forward-looking statements will result or be achieved or accomplished. Important factors that could cause actual results to differ materially from estimates or projections contained in forward-looking statements are described in our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission on October 12, 2004. 37 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK This information updates, and you should read it in conjunction with, information disclosed in our 2003 Annual Report on Form 10-K, in addition to the information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There are no material changes in our quantitative and qualitative disclosures about market risks from those reported in our 2003 Annual Report on Form 10-K, except as discussed below: INTEREST RATE RISK During 2004, we sold our remaining third party long-term power purchase and our power supply derivative contracts held by Utility Contract Funding and Mohawk River Funding IV, which eliminated our exposure to interest rate risk related to these contracts. Our remaining exposure to interest rate risk relates to our long-term financing obligations. 38 ITEM 4. CONTROLS AND PROCEDURES During 2003, we initiated a project to ensure compliance with Section 404 of the Sarbanes-Oxley Act of 2002 (SOX), which will apply to us at December 31, 2005. This project entailed a detailed review and documentation of the processes that impact the preparation of our financial statements, an assessment of the risks that could adversely affect the accurate and timely preparation of those financial statements, and the identification of the controls in place to mitigate the risks of untimely or inaccurate preparation of those financial statements. Following the documentation of these processes, we initiated an internal review or "walk-through" of these financial processes by the financial management responsible for those processes to evaluate the design effectiveness of the controls identified to mitigate the risk of material misstatements occurring in our financial statements. We also initiated a detailed process to evaluate the operating effectiveness of our controls over financial reporting. This process involves testing the controls for effectiveness, including a review and inspection of the documentary evidence supporting the operation of the controls on which we are placing reliance. In September 2004, we completed an investigation surrounding matters that gave rise to a restatement of our historical financial statements for the period from 1999 to 2002 and the first nine months of 2003. This investigation identified a number of internal control weaknesses which we reported as material control weaknesses in our 2003 Annual Report on Form 10-K. The following are the internal control deficiencies related to the restatement of our historical financial statements, and those identified as a result of our SOX implementation which we have previously disclosed: - A weak control environment surrounding the booking of our proved natural gas and oil reserves in the Production segment; - Inadequate controls over access to our proved natural gas and oil reserve system; - Inadequate documentation of policies and procedures related to booking proved natural gas and oil reserves; - Ineffective monitoring activities to ensure compliance with existing policies, procedures and accounting conclusions; - Lack of formal evidence to substantiate monitoring activities were adequately performed (e.g., monitoring activities, such as meetings and report reviews, were not always documented in a way to objectively confirm the monitoring activities occurred); - Inadequate change management and security access to our information systems (e.g., program developers were allowed to migrate system changes into production and passwords for some of our applications did not adhere to the corporate policy for effective passwords); - Lack of segregation of duties related to manual journal entry preparation and procurement activities (e.g., our financial accounting system was not designed to prevent the same person from posting an entry that prepared the entry and a buyer of goods could also receive for the goods); and - Untimely preparation and review of volume and account reconciliations. We have communicated to El Paso's Audit Committee and to our external auditors the deficiencies identified to date in our internal controls over financial reporting as well as the remediation efforts that we have underway. We are committed to effectively remediate known deficiencies as expeditiously as possible and continue our extensive efforts to comply with Section 404 of SOX by December 31, 2005. Consequently, we have made the following changes to our internal controls during 2004: - Added members to El Paso's Board of Directors, including its Audit Committee and its executive management team with extensive experience in the natural gas and oil industry; - Formed a committee to provide oversight of the proved natural gas and oil reserve estimation process, which is staffed with appropriate technical, financial reporting and legal expertise; 39 - Continued use of an independent third-party reserve engineering firm, selected by and reporting annually to the Audit Committee of El Paso's Board of Directors, to perform an independent assessment of our proved natural gas and oil reserves; - Formed a centralized proved natural gas and oil reserve evaluation and reporting function, staffed primarily with newly hired personnel that have extensive industry experience, that is separate from the operating divisions and reports to the president of Production and Non-regulated Operations; - Restricted security access to the proved natural gas and oil reserve system to the centralized reserve reporting staff; - Revised our documentation of procedures and controls for estimating proved natural gas and oil reserves; - Enhanced internal audit reviews to monitor booking of proved natural gas and oil reserves; - Implemented standard information system policies and procedures to enforce change management and segregation of responsibilities when migrating programming changes to production and strengthened security policies and procedures around passwords for applications and databases; - Modified systems and procedures to ensure appropriate segregation of responsibilities for manual journal entry preparation and procurement activities; - Formalized our account reconciliation policy and completed all material account reconciliations; and - Developed and implemented formal training to educate company personnel on management's responsibilities mandated by SOX Section 404, the components of the internal control framework on which we rely and the relationship to our company values including accountability, stewardship, integrity and excellence. We are in the process of implementing the following changes to our internal controls, which we expect to have implemented by December 31, 2004: - Improved training regarding SEC guidelines for booking proved natural gas and oil reserves; - Formal communication of procedures for documenting accounting conclusions involving interpretation of complex accounting standards, including identification of critical factors that support the basis for our conclusion; - Evaluation, formalization and communication of required policies and procedures; - Improved monitoring activities to ensure compliance with policies, procedures and accounting conclusions; and - Review the adequacy, proficiency and training of our finance and accounting staff. Many of the deficiencies in our internal controls that we have identified are likely the result of significant changes the company has undergone during the past five years as a result of major acquisitions and reorganizations. As we continue our SOX Section 404 compliance efforts, including the testing of the effectiveness of our internal controls, we may identify additional deficiencies in our system of internal controls that either individually or in the aggregate may represent a material weakness requiring additional remediation efforts. We did not make any changes to our internal controls over financial reporting during the six months ended June 30, 2004, that have had a material adverse affect or are reasonably likely to have a material adverse affect on our internal controls over financial reporting. We also reviewed our overall disclosure controls and procedures for the quarter ended June 30, 2004. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our principal 40 executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As a result of the internal control deficiencies described above, we concluded that our disclosure controls and procedures were not effective at June 30, 2004. However, we expanded our procedures to include additional analysis and other post-closing procedures to ensure that the disclosure controls and procedures over the preparation of these financial statements were effective. 41 PART II -- OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS See Part I, Item 1, Note 8, which is incorporated herein by reference. Additional information about our legal proceedings can be found in Part I, Item 3 of our Annual Report on Form 10-K filed with the Securities and Exchange Commission on October 12, 2004. ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS None. ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. ITEM 5. OTHER INFORMATION None. ITEM 6. EXHIBITS Each exhibit identified below is filed as a part of this report. Exhibits not incorporated by reference to a prior filing are designated by an "*". All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Undertaking We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the U.S. Securities and Exchange Commission, upon request, all constituent instruments defining the rights of holders of our long-term debt not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets. 42 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. EL PASO CORPORATION Date: December 3, 2004 /s/ D. DWIGHT SCOTT ------------------------------------ D. Dwight Scott Executive Vice President, Chief Financial Officer, and Director (Principal Financial Officer) Date: December 3, 2004 /s/ JEFFREY I. BEASON ------------------------------------ Jeffrey I. Beason Senior Vice President and Controller (Principal Accounting Officer) 43 EXHIBIT INDEX Each exhibit identified below is filed as a part of this report. Exhibits not incorporated by reference to a prior filing are designated by an "*". All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

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